Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2018 | Oct. 29, 2018 | |
Document and Entity Information [Abstract] | ||
Entity Registrant Name | Williams Companies Inc | |
Entity Central Index Key | 107,263 | |
Document Type | 10-Q | |
Document Period End Date | Sep. 30, 2018 | |
Amendment Flag | false | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus | Q3 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Small Business | false | |
Entity Emerging Growth Company | false | |
Entity Common Stock, Shares Outstanding | 1,210,542,031 |
Consolidated Statement of Incom
Consolidated Statement of Income (Unaudited) - USD ($) shares in Thousands, $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Revenues: | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 2,280 | $ 6,423 | ||
Service revenues – commodity consideration (Note 2) | 121 | $ 0 | 316 | $ 0 |
Total revenues | 2,303 | 1,891 | 6,482 | 5,803 |
Costs and expenses: | ||||
Processing commodity expenses (Note 2) | 30 | 0 | 91 | 0 |
Operating and maintenance expenses | 389 | 403 | 1,134 | 1,166 |
Depreciation and amortization expenses | 425 | 433 | 1,290 | 1,308 |
Selling, general, and administrative expenses | 174 | 138 | 436 | 452 |
Gain on sale of Geismar Interest (Note 4) | 0 | (1,095) | 0 | (1,095) |
Impairment of certain assets (Note 12) | 0 | 1,210 | 66 | 1,236 |
Other (income) expense – net | (6) | 24 | 24 | 34 |
Total costs and expenses | 1,802 | 1,617 | 5,080 | 4,721 |
Operating income (loss) | 501 | 274 | 1,402 | 1,082 |
Equity earnings (losses) | 105 | 115 | 279 | 347 |
Other investing income (loss) – net (Note 5) | 2 | 4 | 74 | 278 |
Interest incurred | (286) | (275) | (856) | (842) |
Interest capitalized | 16 | 8 | 38 | 24 |
Other income (expense) – net | 52 | 23 | 99 | 124 |
Income (loss) before income taxes | 390 | 149 | 1,036 | 1,013 |
Provision (benefit) for income taxes | 190 | 24 | 297 | 126 |
Net income (loss) | 200 | 125 | 739 | 887 |
Less: Net income (loss) attributable to noncontrolling interests | 71 | 92 | 323 | 400 |
Net income (loss) attributable to The Williams Companies, Inc. | 129 | 33 | 416 | 487 |
Preferred stock dividends (Note 11) | 0 | 0 | 0 | 0 |
Net income (loss) available to common stockholders | $ 129 | $ 33 | $ 416 | $ 487 |
Basic earnings (loss) per common share: | ||||
Net income (loss) | $ 0.13 | $ 0.04 | $ 0.47 | $ 0.59 |
Weighted-average shares (thousands) | 1,023,587 | 826,779 | 893,706 | 825,925 |
Diluted earnings (loss) per common share: | ||||
Net income (loss) | $ 0.13 | $ 0.04 | $ 0.46 | $ 0.59 |
Weighted-average shares (thousands) | 1,026,504 | 829,368 | 896,322 | 828,150 |
Cash dividends declared per common share | $ 0.34 | $ 0.30 | $ 1.02 | $ 0.9 |
Service [Member] | ||||
Revenues: | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 1,371 | $ 1,310 | $ 4,062 | $ 3,853 |
Product [Member] | ||||
Revenues: | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 811 | 581 | 2,104 | 1,950 |
Oil and Gas, Purchased [Member] | ||||
Costs and expenses: | ||||
Product costs | $ 790 | $ 504 | $ 2,039 | $ 1,620 |
Consolidated Statement of Compr
Consolidated Statement of Comprehensive Income (Unaudited) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Comprehensive income (loss): | ||||
Net income (loss) | $ 200 | $ 125 | $ 739 | $ 887 |
Cash flow hedging activities: | ||||
Net unrealized gain (loss) from derivative instruments, net of taxes of $3 and $6 in 2018, and $2 and $1 in 2017 | (5) | (9) | (19) | (5) |
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of ($2) and ($3) in 2018, and $1 and $1 in 2017 | 7 | 2 | 10 | 0 |
Pension and other postretirement benefits: | ||||
Amortization of prior service cost (credit) included in net periodic benefit cost (credit), net of taxes of $1 and $2 in 2017 | 0 | 0 | 0 | (2) |
Net actuarial gain (loss) arising during the year, net of taxes of ($0) and ($1) in 2018 | 0 | 0 | 4 | 0 |
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of ($3) and ($5) in 2018, and ($2) and ($7) in 2017 | 4 | 4 | 14 | 13 |
Other comprehensive income (loss) | 6 | (3) | 9 | 6 |
Comprehensive income (loss) | 206 | 122 | 748 | 893 |
Less: Comprehensive income (loss) attributable to noncontrolling interests | 72 | 89 | 321 | 398 |
Comprehensive income (loss) attributable to The Williams Companies, Inc. | $ 134 | $ 33 | $ 427 | $ 495 |
Consolidated Statement of Com_2
Consolidated Statement of Comprehensive Income (Parenthetical) (Unaudited) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), after Reclassification, Tax [Abstract] | ||||
Other Comprehensive Income, Unrealized Gain (Loss) on Derivatives Arising During Period, Tax | $ 3 | $ 2 | $ 6 | $ 1 |
Other Comprehensive Income Loss Reclassification Adjustment On Derivatives Included In Net Income Tax | (2) | 1 | (3) | 1 |
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, Tax [Abstract] | ||||
Amortization of prior service cost (credit) included in net periodic benefit cost, taxes | 0 | 1 | 0 | 2 |
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax | 0 | 0 | (1) | 0 |
Amortization of actuarial (gain) loss included in net periodic benefit cost, taxes | $ (3) | $ (2) | $ (5) | $ (7) |
Consolidated Balance Sheet (Una
Consolidated Balance Sheet (Unaudited) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Current assets: | ||
Cash and cash equivalents | $ 42 | $ 899 |
Trade accounts and other receivables (net of allowance of $9 at September 30, 2018 and $9 at December 31, 2017) | 883 | 976 |
Inventories | 153 | 113 |
Assets held for sale (Note 4) | 664 | 7 |
Other current assets and deferred charges | 242 | 184 |
Total current assets | 1,984 | 2,179 |
Investments | 7,427 | 6,552 |
Property, plant, and equipment | 39,953 | 39,513 |
Accumulated depreciation and amortization | (11,279) | (11,302) |
Property, plant, and equipment – net | 28,674 | 28,211 |
Intangible assets – net of accumulated amortization | 8,324 | 8,791 |
Regulatory assets, deferred charges, and other | 744 | 619 |
Total assets | 47,153 | 46,352 |
Current liabilities: | ||
Accounts payable | 739 | 978 |
Liabilities held for sale (Note 4) | 49 | 0 |
Accrued liabilities | 1,117 | 1,167 |
Commercial paper | 823 | 0 |
Long-term debt due within one year | 33 | 501 |
Total current liabilities | 2,761 | 2,646 |
Long-term debt | 21,409 | 20,434 |
Deferred income tax liabilities | 1,648 | 3,147 |
Regulatory liabilities, deferred income, and other | 4,376 | 3,950 |
Contingent liabilities (Note 13) | ||
Stockholders’ equity: | ||
Preferred Stock (Note 11) | 35 | 0 |
Common stock ($1 par value; 1,470 million shares authorized at September 30, 2018 and 960 million shares authorized at December 31, 2017; 1,245 million shares issued at September 30, 2018 and 861 million shares issued at December 31, 2017) | 1,245 | 861 |
Capital in excess of par value | 24,680 | 18,508 |
Retained deficit | (9,018) | (8,434) |
Accumulated other comprehensive income (loss) | (291) | (238) |
Treasury stock, at cost (35 million shares of common stock) | (1,041) | (1,041) |
Total stockholders’ equity | 15,610 | 9,656 |
Noncontrolling interests in consolidated subsidiaries | 1,349 | 6,519 |
Total equity | 16,959 | 16,175 |
Total liabilities and equity | $ 47,153 | $ 46,352 |
Consolidated Balance Sheet (Par
Consolidated Balance Sheet (Parenthetical) (Unaudited) - USD ($) shares in Millions, $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Statement of Financial Position [Abstract] | ||
Allowance for trade accounts and other receivables | $ 9 | $ 9 |
Stockholders’ equity: | ||
Common stock, shares authorized | 1,470 | 960 |
Common stock, par value of shares authorized | $ 1 | $ 1 |
Common stock, shares issued | 1,245 | 861 |
Treasury stock, shares of common shares | 35 | 35 |
Consolidated Statement of Chang
Consolidated Statement of Changes in Equity (Unaudited) - 9 months ended Sep. 30, 2018 - USD ($) $ in Millions | Total | Total Stockholders’ Equity | Preferred Stock [Member] | Common Stock | Capital in Excess of Par Value | Retained Deficit | AOCI | Treasury Stock | Noncontrolling Interests |
December 31, 2017 at Dec. 31, 2017 | $ 16,175 | $ 9,656 | $ 0 | $ 861 | $ 18,508 | $ (8,434) | $ (238) | $ (1,041) | $ 6,519 |
Adoption of ASC 606 (Note 1) | (121) | (84) | 0 | 0 | 0 | (84) | 0 | 0 | (37) |
Adoption of ASU 2018-02 (Note 1) | 0 | 0 | 0 | 0 | 0 | 61 | (61) | 0 | 0 |
Net income (loss) | 739 | 416 | 0 | 0 | 0 | 416 | 0 | 0 | 323 |
Other comprehensive income (loss) | 9 | 11 | 0 | 0 | 0 | 0 | 11 | 0 | (2) |
WPZ Merger (Note 1) | 1,862 | 6,491 | 0 | 382 | 6,112 | 0 | (3) | 0 | (4,629) |
Issuance of preferred stock (Note 11) | 35 | 35 | 35 | 0 | 0 | 0 | 0 | 0 | 0 |
Cash dividends – common stock | (974) | (974) | 0 | 0 | 0 | (974) | 0 | 0 | 0 |
Dividends and distributions to noncontrolling interests | (598) | 0 | 0 | 0 | 0 | 0 | 0 | 0 | (598) |
Stock-based compensation and related common stock issuances | 49 | 49 | 0 | 1 | 48 | 0 | 0 | 0 | 0 |
Sales of limited partner units of Williams Partners L.P. | 46 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 46 |
Changes in ownership of consolidated subsidiaries, net | (4) | 14 | 0 | 0 | 14 | 0 | 0 | 0 | (18) |
Contributions from noncontrolling interests | 13 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 13 |
Deconsolidation of subsidiary (Note 3) | (267) | 0 | 0 | 0 | 0 | 0 | 0 | 0 | (267) |
Other | (5) | (4) | 0 | 1 | (2) | (3) | 0 | 0 | (1) |
Net increase (decrease) in equity | 784 | 5,954 | 35 | 384 | 6,172 | (584) | (53) | 0 | (5,170) |
September 30, 2018 at Sep. 30, 2018 | $ 16,959 | $ 15,610 | $ 35 | $ 1,245 | $ 24,680 | $ (9,018) | $ (291) | $ (1,041) | $ 1,349 |
Consolidated Statement of Cash
Consolidated Statement of Cash Flows (Unaudited) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2017 | |
OPERATING ACTIVITIES: | ||
Net income (loss) | $ 739 | $ 887 |
Adjustments to reconcile to net cash provided (used) by operating activities: | ||
Depreciation and amortization | 1,290 | 1,308 |
Provision (benefit) for deferred income taxes | 351 | 99 |
Equity (earnings) losses | (279) | (347) |
Distributions from unconsolidated affiliates | 507 | 602 |
Net (gain) loss on disposition of equity-method investments | 0 | (269) |
Gain on sale of Geismar Interest (Note 4) | 0 | (1,095) |
Impairment of and net (gain) loss on sale of assets | 64 | 1,225 |
Amortization of stock-based awards | 43 | 61 |
Cash provided (used) by changes in current assets and liabilities: | ||
Accounts and notes receivable | 75 | 118 |
Inventories | (39) | (23) |
Other current assets and deferred charges | (44) | (11) |
Accounts payable | (76) | 47 |
Accrued liabilities | (62) | (161) |
Other, including changes in noncurrent assets and liabilities | (238) | (210) |
Net cash provided (used) by operating activities | 2,331 | 2,231 |
FINANCING ACTIVITIES: | ||
Proceeds from (payments of) commercial paper – net | 821 | (93) |
Proceeds from long-term debt | 3,745 | 3,013 |
Payments of long-term debt | (3,201) | (5,475) |
Proceeds from issuance of common stock | 15 | 2,130 |
Common dividends paid | (974) | (744) |
Dividends and distributions paid to noncontrolling interests | (552) | (636) |
Contributions from noncontrolling interests | 13 | 15 |
Payments for debt issuance costs | (26) | (14) |
Other – net | (46) | (87) |
Net cash provided (used) by financing activities | (205) | (1,891) |
INVESTING ACTIVITIES: | ||
Capital expenditures (1) | (2,659) | (1,700) |
Dispositions – net | (2) | (27) |
Contributions in aid of construction | 395 | 253 |
Proceeds from sale of businesses, net of cash divested | 0 | 2,056 |
Proceeds from dispositions of equity-method investments | 0 | 200 |
Purchases of and contributions to equity-method investments | (803) | (103) |
Other – net | 86 | (17) |
Net cash provided (used) by investing activities | (2,983) | 662 |
Increase (decrease) in cash and cash equivalents | (857) | 1,002 |
Cash and cash equivalents at beginning of year | 899 | 170 |
Cash and cash equivalents at end of period | 42 | 1,172 |
(1) Increases to property, plant, and equipment | (2,482) | (1,826) |
Changes in related accounts payable and accrued liabilities | (177) | 126 |
Capital expenditures (1) | $ (2,659) | $ (1,700) |
General, Description of Busines
General, Description of Business, and Basis of Presentation | 9 Months Ended |
Sep. 30, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
General, Description of Business, and Basis of Presentation [Text Block] | Note 1 – General, Description of Business, and Basis of Presentation General Our accompanying interim consolidated financial statements do not include all the notes in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, 2017, in Exhibit 99.1 of our Form 8-K dated May 3, 2018. The accompanying unaudited financial statements include all normal recurring adjustments and others that, in the opinion of management, are necessary to present fairly our interim financial statements. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Unless the context clearly indicates otherwise, references in this report to “Williams,” “we,” “our,” “us,” or like terms refer to The Williams Companies, Inc. and its subsidiaries. Unless the context clearly indicates otherwise, references to “Williams,” “we,” “our,” and “us” include the operations in which we own interests accounted for as equity-method investments that are not consolidated in our financial statements. When we refer to our equity investees by name, we are referring exclusively to their businesses and operations. WPZ Merger On August 10, 2018, we completed our merger with Williams Partners L.P. (WPZ), pursuant to which we acquired all of the approximately 256 million publicly held outstanding common units of WPZ in exchange for 382 million shares of our common stock (WPZ Merger). Williams continued as the surviving entity. The WPZ Merger was accounted for as a non-cash equity transaction resulting in increases to Common stock of $382 million , Capital in excess of par value of $6.112 billion , and Regulatory assets, deferred charges, and other of $33 million and decreases to Accumulated other comprehensive income (loss) of $3 million , Noncontrolling interests in consolidated subsidiaries of $4.629 billion , and Deferred income tax liabilities of $1.829 billion in the Consolidated Balance Sheet . Prior to the completion of the WPZ Merger and pursuant to its distribution reinvestment program, WPZ had issued 1,230,657 common units to the public in 2018 associated with reinvested distributions of $46 million . Financial Repositioning In January 2017, we entered into agreements with WPZ, wherein we permanently waived the general partner’s incentive distribution rights and converted our 2 percent general partner interest in WPZ to a noneconomic interest in exchange for 289 million newly issued WPZ common units. Pursuant to this agreement, we also purchased approximately 277 thousand WPZ common units for $10 million . Additionally, we purchased approximately 59 million common units of WPZ at a price of $36.08586 per unit in a private placement transaction, funded with proceeds from our equity offering. According to the terms of this agreement, concurrent with WPZ’s quarterly distributions in February 2017 and May 2017, we paid additional consideration totaling $56 million to WPZ for these units. Description of Business We are a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. Our operations are located principally in the United States. Prior to the WPZ Merger, we had one reportable segment, Williams Partners. Beginning in the third-quarter 2018, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are now presented within the following reportable segments: Northeast G&P, Atlantic-Gulf, and West. Prior period segment disclosures have been recast for the new segment presentation. Northeast G&P is comprised of our midstream gathering and processing businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and West Virginia and the Utica Shale region of eastern Ohio, as well as a 66 percent interest in Cardinal Gas Services, L.L.C. (Cardinal) (a consolidated entity), a 62 percent equity-method investment in Utica East Ohio Midstream, LLC, a 69 percent equity-method investment in Laurel Mountain Midstream, LLC, a 58 percent equity-method investment in Caiman Energy II, LLC, and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 66 percent interest in multiple gathering systems in the Marcellus Shale (Appalachia Midstream Investments). Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transcontinental Gas Pipe Line Company, LLC (Transco), and significant natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One LLC (Gulfstar One) (a consolidated entity), which is a proprietary floating production system, and various petrochemical and feedstock pipelines in the Gulf Coast region, as well as a 50 percent equity-method investment in Gulfstream Natural Gas System, L.L.C., a 41 percent interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity), which is developing a pipeline project (see Note 3 – Variable Interest Entities ), and a 60 percent equity-method investment in Discovery Producer Services LLC. West is comprised of our interstate natural gas pipeline, Northwest Pipeline LLC (Northwest Pipeline), and our gathering, processing, and treating operations in New Mexico, Colorado, and Wyoming, as well as the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware, and Permian basins. This segment also includes our natural gas liquid (NGL) and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in Overland Pass Pipeline, LLC, a 50 percent interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope) (an equity-method investment following deconsolidation as of June 30, 2018), a 43 percent equity-method investment in Rocky Mountain Midstream Holdings LLC (RMM), and our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region (see Note 5 – Investing Activities ). All remaining business activities, including our former Williams Olefins, L.L.C., a wholly owned subsidiary which owned our 88.5 percent undivided interest in the Geismar, Louisiana, olefins plant (Geismar Interest) (see Note 4 – Divestitures and Assets Held for Sale ), as well as corporate activities, are included in Other. Basis of Presentation Significant risks and uncertainties We may monetize assets that are not core to our strategy which could result in impairments of certain equity-method investments, property, plant, and equipment, and intangible assets. Such impairments could potentially be caused by indications of fair value implied through the monetization process or, in the case of asset dispositions that are part of a broader asset group, the impact of the loss of future estimated cash flows. Proposition 112 On November 6, 2018, citizens of Colorado will vote on Proposition 112, a ballot measure that could significantly increase setback distances from occupied structures or other vulnerable areas, as defined or designated, for any new oil and gas development in the state, critically restricting or banning such activities. If the measure is approved, it could still be subject to modification or amendment by the Colorado legislature. An unfavorable outcome could adversely impact the operations, and ultimately the value, of our businesses and investments in Colorado, notably our recent investment in RMM (see Note 5 – Investing Activities ). FERC Income Tax Policy Revision On March 15, 2018, the Federal Energy Regulatory Commission (FERC) issued a revised policy statement (the March 15 Statement) regarding the recovery of income tax costs in rates of natural gas pipelines. The FERC found that an impermissible double recovery results from granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. As a result, the FERC will no longer permit an MLP pipeline to recover an income tax allowance in its cost of service. The FERC further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings. One of the benefits of the recent WPZ Merger is to allow our FERC-regulated pipelines to continue to recover an income tax allowance in their cost of service rates. On July 18, 2018, the FERC issued an order dismissing the requests for rehearing and clarification of the revised policy statement. In addition, the FERC provided guidance that an MLP pipeline (or other pass-through entity) no longer recovering an income tax allowance pursuant to the revised policy may eliminate previously accumulated deferred income taxes (ADIT) from its cost of service instead of flowing these ADIT balances to ratepayers. This guidance, if implemented, would significantly mitigate the impact of the March 15 Statement. However, the FERC stated that the revised policy statement and such guidance do not establish a binding rule but are instead expressions of general policy intent designed to provide guidance by notifying entities of the course of action the FERC intends to follow in future adjudications. To the extent the FERC addresses these issues in future proceedings, it will consider any arguments regarding not only the application of the revised policy to the facts of the case, but also any arguments regarding the underlying validity of the policy itself. The FERC’s guidance on ADIT likely will be challenged by customers and state commissions, which would result in a long period of revenue uncertainty for pipelines eliminating ADIT from their cost of service. The WPZ Merger has the additional benefit of eliminating this uncertainty. On March 15, 2018, the FERC also issued a Notice of Proposed Rulemaking proposing a filing process that will allow it to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the recent reduction in the corporate income tax rate in the Tax Cuts and Jobs Act (Tax Reform) and the revised policy statement. On July 18, 2018, the FERC issued a Final Rule, retaining the filing requirement and reaffirming the options that pipelines have to either reflect the reduced tax rate or explain why no rate change is necessary. The FERC also clarified that a natural gas company organized as a pass-through entity and all of whose income or losses are consolidated on the federal income tax return of its corporate parent is considered to be subject to the federal corporate income tax and is thus eligible for a tax allowance. We believe this Final Rule and the previously discussed WPZ Merger allow for the continued recovery of income tax allowances in Transco’s and Northwest Pipeline’s rates. Further, Transco’s August 31, 2018 general rate case filing reflects a tax allowance based on this clarification, and the FERC’s September 28, 2018 order in the rate case proceeding finds that Transco is exempt from the Final Rule’s Form 501-G filing requirement. In addition, on October 19, 2018, Northwest Pipeline filed a petition requesting that the FERC waive its Form 501-G filing requirement under this Final Rule because the reduction in the corporate income tax in Tax Reform is already addressed in its settlement. On March 15, 2018, the FERC also issued a Notice of Inquiry seeking comments on the additional impacts of Tax Reform on jurisdictional rates, particularly whether, and if so how, the FERC should address changes relating to ADIT amounts after the corporate income tax rate reduction and bonus depreciation rules, as well as whether other features of Tax Reform require FERC action. We are evaluating the impact of these developments on our interstate natural gas pipelines and currently expect any associated impacts would be prospective and determined through subsequent rate proceedings. We also continue to monitor developments that may impact our regulatory liabilities resulting from Tax Reform. It is reasonably possible that future tariff-based rates collected by our interstate natural gas pipelines may be adversely impacted. Accounting standards issued and adopted During the first quarter of 2018, we early adopted Accounting Standards Update (ASU) 2018-02 “Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income” (ASU 2018-02). As a result of Tax Reform lowering the federal income tax rate, the tax effects of items within accumulated other comprehensive income may not reflect the appropriate tax rate. ASU 2018-02 allows for the reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from Tax Reform. The adoption of ASU 2018-02 resulted in the reclassification of $61 million from Accumulated other comprehensive income (loss) to Retained deficit on our Consolidated Balance Sheet . Effective January 1, 2018, we adopted ASU 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities” (ASU 2017-12). ASU 2017-12 applies to entities that elect hedge accounting in accordance with Accounting Standards Codification (ASC) 815. The ASU affects both the designation and measurement guidance for hedging relationships and the presentation of hedging results. ASU 2017-12 was applied using a modified retrospective approach for cash flow and net investment hedges existing at the date of adoption and prospectively for the presentation and disclosure guidance. The adoption of ASU 2017-12 did not have a significant impact on our consolidated financial statements. Effective January 1, 2018, we adopted ASU 2017-07 “Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost” (ASU 2017-07). ASU 2017-07 requires employers to report the service cost component of net benefit cost in the same line item or items as other compensation costs arising from employee services. The other components of net benefit cost must be presented in the income statement separately from the service cost component and outside Operating income (loss) . Only the service cost component is now eligible for capitalization when applicable. The presentation aspect of ASU 2017-07 must be applied retrospectively and the capitalization requirement prospectively. In accordance with this adoption, we have conformed the prior year presentation, which resulted in increases of $3 million and $9 million to Operating and maintenance expenses with corresponding decreases to Operating income (loss) and increases of $3 million and $9 million to Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Income for the three- and nine-month periods ended September 30, 2017, respectively. Effective January 1, 2018, we adopted ASU 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” (ASU 2016-15). Among other things, ASU 2016-15 permits an accounting policy election to classify distributions received from equity-method investees using either the cumulative earnings approach or the nature of distribution approach. We have elected to apply the nature of distribution approach and have retrospectively conformed the prior year presentation within the Consolidated Statement of Cash Flows in accordance with ASU 2016-15. For the period ended September 30, 2017, amounts previously presented as Distributions from unconsolidated affiliates in excess of cumulative earnings within Investing Activities are now presented as part of Distributions from unconsolidated affiliates within Operating Activities , resulting in an increase to Net cash provided (used) by operating activities of $394 million with a corresponding reduction in Net cash provided (used) by investing activities . In May 2014, the Financial Accounting Standards Board (FASB) issued ASU 2014-09 establishing ASC Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard became effective for interim and annual reporting periods beginning after December 15, 2017. We adopted the provisions of ASC 606 effective January 1, 2018, utilizing the modified retrospective transition method for all contracts with customers, which included applying the provisions of ASC 606 beginning January 1, 2018, to all contracts not completed as of that date with the cumulative effect of applying the standard for periods prior to January 1, 2018, as an adjustment to Total equity , net of tax, upon adoption. As a result of our adoption, the cumulative impact to our Total equity , net of tax, at January 1, 2018, was a decrease of $121 million in the Consolidated Balance Sheet . For each revenue contract type, we conducted a formal contract review process to evaluate the impact of ASC 606. The adjustment to Total equity upon adoption of ASC 606 is primarily comprised of the impact to the timing of recognition of deferred revenue (contract liabilities) associated with certain contracts which underwent modifications in periods prior to January 1, 2018. Under the provisions of ASC 606, when a contract modification does not increase both the scope and price of the contract, and the remaining goods and services are distinct from the goods and services transferred prior to the modification, the modification is treated as a termination of the existing contract and the creation of a new contract. ASC 606 requires that the transaction price, including any remaining contract liabilities from the old contract, be allocated to the performance obligations over the term of the new contract. The contract modification adjustments are partially offset by the impact of changes to the timing of recognizing revenue which is subject to the constraint on estimates of variable consideration of certain contracts. The constraint of variable consideration will result in the acceleration of revenue recognition and corresponding de-recognition of contract liabilities for certain contracts (as compared to the previous revenue recognition model) as a result of our assessment that it is probable such recognition would not result in a significant revenue reversal in the future. Additionally, under ASC 606, our revenues will increase in situations where we receive noncash consideration, which exists primarily in certain of our gas processing contracts where we receive commodities as full or partial consideration for services provided. This increase in revenues will be offset by a similar increase in costs and expenses when the commodities received are subsequently sold. Financial systems and internal controls necessary for adoption were implemented effective January 1, 2018. (See Note 2 – Revenue Recognition .) Accounting standards issued but not yet adopted In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities will be required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019. Early adoption is permitted. The standard requires varying transition methods for the different categories of amendments. Although we do not expect ASU 2016-13 to have a significant impact, it could impact our trade receivables as the related allowance for credit losses will be recognized earlier under the expected loss model. In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 modifies the definition of a lease, requires a dual approach to lease classification similar to current lease accounting, and causes lessees to recognize operating leases on the balance sheet as a lease liability measured as the present value of the future lease payments with a corresponding right-of-use asset, with an exception for leases with a term of one year or less. Additional disclosures will also be required regarding the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01 “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842” (ASU 2018-01). Per ASU 2018-01, land easements and rights-of-way are required to be assessed under ASU 2016-02 to determine whether the arrangements are or contain a lease. ASU 2018-01 permits an entity to elect a transition practical expedient to not apply ASU 2016-02 to land easements that exist or expired before the effective date of ASU 2016-02 and that were not previously assessed under the previous lease guidance in ASC Topic 840 “Leases.” In July 2018, the FASB issued ASU 2018-11 “Leases (Topic 842): Targeted Improvements” (ASU 2018-11). Prior to ASU 2018-11, a modified retrospective transition was required for financing or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements. ASU 2018-11 allows entities an additional transition method to the existing requirements whereby an entity could adopt the provisions of ASU 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial statements for periods prior to adoption. ASU 2018-11 also allows a practical expedient that permits lessors to not separate non-lease components from the associated lease component if certain conditions are present. ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. We will adopt ASU 2016-02 effective January 1, 2019. We are in the process of finalizing our review of contracts to identify leases based on the modified definition of a lease and identifying changes to our internal controls to support management in the accounting for and disclosure of leasing activities upon adoption of ASU 2016-02. We implemented a financial lease accounting system to assist management in the accounting for leases upon adoption. While we are still in the process of completing our implementation evaluation of ASU 2016-02, we currently believe the most significant changes to our financial statements relate to the recognition of a lease liability and offsetting right-of-use asset in our Consolidated Balance Sheet for operating leases. We are also evaluating ASU 2016-02’s available practical expedients on adoption, which we generally expect to elect. |
Revenue Recognition
Revenue Recognition | 9 Months Ended |
Sep. 30, 2018 | |
Revenue Recognition [Abstract] | |
Revenue Recognition [Text Block] | Note 2 – Revenue Recognition Customers in our gas pipeline businesses are comprised of public utilities, municipalities, gas marketers and producers, intrastate pipelines, direct industrial users, and electrical generators. Customers in our midstream businesses are comprised of oil and natural gas producer counterparties. Customers for our product sales are comprised of public utilities, gas marketers, and direct industrial users. A performance obligation is a promise in a contract to transfer a distinct good or service (or integrated package of goods or services) to the customer. A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue, when, or as, the performance obligation is satisfied. A performance obligation is distinct if the service is separately identifiable from other items in the integrated package of services and if a customer can benefit from it on its own or with other resources that are readily available to the customer. An integrated package of services typically represents a single performance obligation if the services are contained within the same contract or within multiple contracts entered into in contemplation with one another that are highly interdependent or highly interrelated, meaning each of the services is significantly affected by one or more of the other services in the contract. Service revenue contracts from our gas pipeline and midstream businesses contain a series of distinct services, with the majority of our contracts having a single performance obligation that is satisfied over time as the customer simultaneously receives and consumes the benefits provided by our performance. Most of our product sales contracts have a single performance obligation with revenue recognized at a point in time when the products have been sold and delivered to the customer. Certain customers reimburse us for costs we incur associated with construction of property, plant, and equipment utilized in our operations. For our rate-regulated gas pipeline businesses that apply ASC 980. "Regulated Operations" (Topic 980), we follow FERC guidelines with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-negotiable in nature; thus, the construction activities do not represent an ongoing major and central operation of our gas pipeline businesses and are not within the scope of ASC 606. Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset. For our midstream businesses, reimbursement and service contracts with customers are viewed together as providing the same commercial objective, as we have the ability to negotiate the mix of consideration between reimbursements and amounts billed over time. Accordingly, we generally recognize reimbursements of construction costs from customers on a gross basis as a contract liability separate from the associated costs included within property, plant, and equipment. The contract liability is recognized into service revenues as the underlying performance obligations are satisfied. Service Revenues Gas pipeline businesses Revenues from our interstate natural gas pipeline businesses, which are included within the caption “Regulated interstate natural gas transportation and storage” in the revenue by category table below and are subject to regulation by certain state and federal authorities, including the FERC, include both firm and interruptible transportation and storage contracts. Firm transportation and storage agreements provide for a reservation charge based on the pipeline or storage capacity reserved, and a commodity charge based on the volume of natural gas delivered/stored, each at rates specified in our FERC tariffs or based on negotiated contractual rates, with contract terms that are generally long-term in nature. Most of our long-term contracts contain an evergreen provision, which allows the contracts to be extended for periods primarily up to one year in length an indefinite number of times following the specified contract term and until terminated generally by either us or the customer. Interruptible transportation and storage agreements provide for a volumetric charge based on actual commodity transportation or storage utilized in the period in which those services are provided, and the contracts are generally limited to one-month periods or less. Our performance obligations related to our interstate natural gas pipeline businesses include the following: • Guaranteed transportation or storage under firm transportation and storage contracts—an integrated package of services typically constituting a single performance obligation, which includes standing ready to provide such services and receiving, transporting or storing (as applicable), and redelivering commodities; • Interruptible transportation and storage under interruptible transportation and storage contracts—an integrated package of services typically constituting a single performance obligation, which includes receiving, transporting or storing (as applicable), and redelivering commodities upon nomination by the customer. In situations where we consider the integrated package of services as a single performance obligation, which represents a majority of our interstate natural gas pipeline contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to stand ready (with regard to firm transportation and storage contracts), receive, transport or store, and redeliver natural gas to the customer; therefore, revenue is recognized at the completion of the integrated package of services which represents a single performance obligation. We recognize revenues for reservation charges over the performance obligation period, which is the contract term, regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges from both firm and interruptible transportation services and storage services are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility because they specifically relate to our efforts to provide these distinct services. Generally, reservation charges and commodity charges in our interstate natural gas pipeline businesses are recognized as revenue in the same period they are invoiced to our customers. As a result of the ratemaking process, certain amounts collected by us may be subject to refund upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks. Midstream businesses Revenues from our midstream businesses, which are included in the caption titled “Non-regulated gathering, processing, transportation, and storage” in the revenue by category table below, include contracts for natural gas gathering, processing, treating, compression, transportation, and other related services with contract terms that are generally long-term in nature and may extend up to the production life of the associated reservoir. Additionally, our midstream businesses generate revenues from fees charged for storing customers’ natural gas and NGLs, generally under prepaid contracted storage capacity contracts. In situations where we provide an integrated package of services combined into a single performance obligation, which represents a majority of this class of contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to provide gathering, processing, transportation, storage, and related services resulting in the delivery, or redelivery in the context of storage services, of pipeline-quality natural gas and NGLs to the customer. As such, revenue is recognized at the daily completion of the integrated package of services as the integrated package represents a single performance obligation. Additionally, certain contracts in our midstream businesses contain fixed or upfront payment terms that result in the deferral of revenues until such services have been performed or such capacity has been made available. We also earn revenues from offshore crude oil and natural gas gathering and transportation and offshore production handling. These services represent an integrated package of services and are considered a single distinct performance obligation for which we recognize revenues as the services are provided to the customer. We generally earn a contractually stated fee per unit for the volume of product transported, gathered, processed, or stored. The rate is generally fixed; however, certain contracts contain variable rates that are subject to change based on commodity prices, levels of throughput, or an annual adjustment based on a formulaic cost of service calculation. In addition, we have contracts with contractually stated fees that decline over the contract term, such as declines based on the passage of time periods or achievement of cumulative throughput amounts. For all of our contracts, we allocate the transaction price to each performance obligation based on the relative standalone selling price. The excess of consideration received over revenue recognized results in the deferral of those amounts until future periods based on a units of production or straight-line methodology. Certain of our gas gathering and processing agreements have minimum volume commitments (MVC). If a customer under such an agreement fails to meet its MVC for a specified period (thus not exercising all the contractual rights to gathering and processing services within the specified period, herein referred to as “breakage”), it is obligated to pay a contractually determined fee based upon the shortfall between the actual gathered or processed volumes and the MVC for the period contained in the contract. When we conclude it is probable that the customer will not exercise all or a portion of its remaining rights, we recognize revenue associated with such breakage amount in proportion to the pattern of exercised rights within the respective MVC period. Under keep-whole and percent-of-liquids processing contracts, we receive commodity consideration in the form of NGLs and take title to the NGLs at the tailgate of the plant. We recognize such commodity consideration as service revenue based on the market value of the NGLs retained at the time the processing is provided. The current market value, as opposed to the market value at the contract inception date, is used due to a combination of factors, including the fact that the volume, mix, and market price of NGL consideration to be received is unknown at the time of contract execution and is not specified in our contracts with customers. Additionally, product sales revenue (discussed below) is recognized upon the sale of the NGLs to a third party based on the sales price at the time of sale. As a result, revenue is recognized both at the time the processing service is provided in Service revenues – commodity consideration and at the time the NGLs retained as part of the processing service are sold in Product sales . The recognition of revenue related to commodity consideration has the impact of increasing the book value of NGL inventory, resulting in higher cost of goods sold at the time of sale. Given that most inventory is sold in the same period that it is generated, the impact of these transactions is expected to have little impact to operating income. Product Sales In the course of providing transportation services to customers of our gas pipeline businesses and gathering and processing services to customers of our midstream businesses, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers. The resulting imbalances are primarily settled through the purchase or sale of natural gas with each customer under terms provided for in our FERC tariffs or gathering and processing agreements, respectively. Revenue is recognized from the sale of natural gas upon settlement of imbalances. In certain instances, we purchase NGLs, crude oil, and natural gas from our oil and natural gas producer customers. In addition, we retain NGLs as consideration in certain processing arrangements, as discussed above in the Service Revenues - Midstream businesses section. We recognize revenue from the sale of these commodities when the products have been sold and delivered. Our product sales contracts are primarily short-term contracts based on prevailing market rates at the time of the transaction. Revenue by Category The following table presents our revenue disaggregated by major service line: Northeast Midstream Atlantic- Gulf Midstream West Midstream Transco Northwest Pipeline Other Intercompany Eliminations Total (Millions) Three Months Ended September 30, 2018 Revenues from contracts with customers: Service revenues: Non-regulated gathering, processing, transportation, and storage: Monetary consideration $ 219 $ 139 $ 409 $ — $ — $ 1 $ (19 ) $ 749 Commodity consideration 5 19 97 — — — — 121 Regulated interstate natural gas transportation and storage — — — 457 110 — (1 ) 566 Other 23 4 11 — — — (4 ) 34 Total service revenues 247 162 517 457 110 1 (24 ) 1,470 Product Sales: NGL and natural gas 69 88 720 41 — — (117 ) 801 Other — — 12 — — — (3 ) 9 Total product sales 69 88 732 41 — — (120 ) 810 Total revenues from contracts with customers 316 250 1,249 498 110 1 (144 ) 2,280 Other revenues (1) 6 5 3 3 — 9 (3 ) 23 Total revenues $ 322 $ 255 $ 1,252 $ 501 $ 110 $ 10 $ (147 ) $ 2,303 Nine Months Ended September 30, 2018 Revenues from contracts with customers: Service revenues: Non-regulated gathering, processing, transportation, and storage: Monetary consideration $ 626 $ 404 $ 1,231 $ — $ — $ 2 $ (55 ) $ 2,208 Commodity consideration 14 45 257 — — — — 316 Regulated interstate natural gas transportation and storage — — — 1,368 330 — (2 ) 1,696 Other 65 12 35 1 — — (10 ) 103 Total service revenues 705 461 1,523 1,369 330 2 (67 ) 4,323 Product Sales: NGL and natural gas 242 232 1,799 96 — — (285 ) 2,084 Other — — 20 — — — (4 ) 16 Total product sales 242 232 1,819 96 — — (289 ) 2,100 Total revenues from contracts with customers 947 693 3,342 1,465 330 2 (356 ) 6,423 Other revenues (1) 16 14 6 8 — 24 (9 ) 59 Total revenues $ 963 $ 707 $ 3,348 $ 1,473 $ 330 $ 26 $ (365 ) $ 6,482 ______________________________ (1) Service revenues in our Consolidated Statement of Income include leasing revenues associated with our headquarters building and management fees that we receive for certain services we provide to operated joint ventures and other investments. The leasing revenues and the management fees do not constitute revenue from contracts with customers. Product sales in our Consolidated Statement of Income include amounts associated with our derivative contracts that are not within the scope of ASC 606. Contract Assets Our contract assets primarily consist of revenue recognized under contracts containing MVC features whereby management has concluded it is probable there will be a short-fall payment at the end of the current MVC period, which typically follows the calendar year, and that a significant reversal of revenue recognized currently for the future MVC payment will not occur. As a result, our contract assets related to our future MVC payments are generally expected to be collected within the next 12 months and are included within Other current assets and deferred charges in our Consolidated Balance Sheet until such time as the MVC short-fall payments are invoiced to the customer. The following table presents a reconciliation of our contract assets: Quarter-to-Date September 30, 2018 Year-to-Date September 30, 2018 (Millions) Balance at beginning of period $ 39 $ 4 Revenue recognized in excess of cash received 17 53 Minimum volume commitments invoiced — (1 ) Balance at end of period $ 56 $ 56 Contract Liabilities Our contract liabilities consist of advance payments primarily from midstream business customers which include construction reimbursements, prepayments, and other billings for which future services are to be provided under the contract. These amounts are deferred until recognized in revenue when the associated performance obligation has been satisfied, which is primarily based on a units of production methodology over the remaining contractual service periods, and are classified as current or noncurrent according to when such amounts are expected to be recognized. Current and noncurrent contract liabilities are included within Accrued liabilities and Regulatory liabilities, deferred income, and other , respectively, in our Consolidated Balance Sheet. Contracts requiring advance payments and the recognition of contract liabilities are evaluated to determine whether the advance payments provide us with a significant financing benefit. This determination is based on the combined effect of the expected length of time between when we transfer the promised good or service to the customer, when the customer pays for those goods or services, and the prevailing interest rates. We have assessed our contracts for significant financing components and determined that one group of contracts entered into in contemplation of one another for certain capital reimbursements contains a significant financing component. As a result, we recognize noncash interest expense based on the effective interest method and revenue (noncash) is recognized when the underlying asset is placed into service utilizing a units of production or straight-line methodology over the life of the corresponding customer contract. The following table presents a reconciliation of our contract liabilities: Quarter-to-Date September 30, 2018 Year-to-Date September 30, 2018 (Millions) Balance at beginning of period $ 1,535 $ 1,596 Payments received and deferred 62 280 Deconsolidation of Jackalope interest (Note 3) — (52 ) Recognized in revenue (112 ) (339 ) Balance at end of period $ 1,485 $ 1,485 The following table presents the amount of the contract liabilities balance as of September 30, 2018 , expected to be recognized as revenue in each of the next five years as performance obligations are expected to be satisfied: (Millions) 2018 (remainder) $ 191 2019 257 2020 129 2021 110 2022 103 2023 100 Thereafter 595 Total $ 1,485 Remaining Performance Obligations The following table presents the transaction price allocated to the remaining performance obligations under certain contracts as of September 30, 2018 . These primarily include long-term contracts containing MVCs associated with our midstream businesses, fixed payments associated with offshore production handling, and reservation charges on contracted capacity on our gas pipeline firm transportation contracts with customers, as well as storage capacity contracts. Amounts included in the table below for our interstate natural gas pipeline businesses reflect the rates for such services in our current FERC tariffs for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes is not currently known. As a practical expedient permitted by ASC 606, this table excludes variable consideration as well as consideration in contracts that is recognized in revenue as billed. It also excludes consideration received prior to September 30, 2018 , that will be recognized in future periods (see above for Contract Liabilities and the expected recognition of those amounts within revenue). As noted above, certain of our contracts contain evergreen and other renewal provisions for periods beyond the initial term of the contract. The remaining performance obligation amounts as of September 30, 2018 , do not consider potential future performance obligations for which the renewal has not been exercised. The table below also does not include contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service. (Millions) 2018 (remainder) $ 624 2019 2,465 2020 2,274 2021 2,106 2022 1,830 2023 1,650 Thereafter 12,471 Total $ 23,420 The table above excludes remaining performance obligations associated with the Atlantic Sunrise expansion project for which we received FERC authorization to place into service in October 2018. We anticipate annual performance obligations of approximately $420 million associated with Atlantic Sunrise over the term of the contracts. Accounts Receivable We do not offer extended payment terms and typically receive payment within one month. We consider receivables past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectability is assured. The following is a summary of our Trade accounts and other receivables as it relates to contracts with customers: September 30, 2018 January 1, 2018 (Millions) Accounts receivable related to revenues from contracts with customers $ 795 $ 958 Other accounts receivable 88 18 Total reflected in Trade accounts and other receivables $ 883 $ 976 Impact of Adoption of ASC 606 The following table depicts the impact of the adoption of ASC 606 on our 2018 financial statements. The adjustment to Intangible assets – net of accumulated amortization in the table below relates to the recognition under ASC 606 of contract assets for MVC-related contracts associated with a 2014 acquisition. The recognition of these contract assets resulted in a lower purchase price allocation to intangible assets. The adoption of ASC 606 did not result in adjustments to total operating, investing, or financing cash flows. As Reported Adjustments resulting from adoption of ASC 606 Balance without adoption of ASC 606 (Millions) Consolidated Statement of Income Three Months Ended September 30, 2018 Service revenues $ 1,371 $ 5 $ 1,376 Service revenues – commodity consideration 121 (121 ) — Product sales 811 44 855 Total revenues 2,303 (72 ) 2,231 Product costs 790 (48 ) 742 Processing commodity expenses 30 (30 ) — Depreciation and amortization expenses 425 1 426 Total costs and expenses 1,802 (77 ) 1,725 Operating income (loss) 501 5 506 Interest incurred (286 ) 4 (282 ) Interest capitalized 16 (2 ) 14 Income (loss) before income taxes 390 7 397 Provision (benefit) for income taxes 190 1 191 Net income (loss) 200 6 206 Less: Net income (loss) attributable to noncontrolling interests 71 (1 ) 70 Net income (loss) attributable to The Williams Companies, Inc. 129 7 136 Basic earnings (loss) per common share $ 0.13 $ 0.01 $ 0.14 Diluted earnings (loss) per common share $ 0.13 $ 0.01 $ 0.14 Nine Months Ended September 30, 2018 Service revenues $ 4,062 $ 16 $ 4,078 Service revenues – commodity consideration 316 (316 ) — Product sales 2,104 86 2,190 Total revenues 6,482 (214 ) 6,268 Product costs 2,039 (143 ) 1,896 Processing commodity expenses 91 (91 ) — Operating and maintenance expenses 1,134 3 1,137 Depreciation and amortization expenses 1,290 2 1,292 Total costs and expenses 5,080 (229 ) 4,851 As Reported Adjustments resulting from adoption of ASC 606 Balance without adoption of ASC 606 (Millions) Operating income (loss) $ 1,402 $ 15 $ 1,417 Equity earnings (losses) 279 1 280 Other investing income (loss) - net 74 (9 ) 65 Interest incurred (856 ) 11 (845 ) Interest capitalized 38 (6 ) 32 Income (loss) before income taxes 1,036 12 1,048 Provision (benefit) for income taxes 297 1 298 Net income (loss) 739 11 750 Net income (loss) attributable to The Williams Companies, Inc. 416 11 427 Basic earnings (loss) per common share $ 0.47 $ 0.01 $ 0.48 Diluted earnings (loss) per common share $ 0.46 $ 0.01 $ 0.47 Consolidated Statement of Comprehensive Income Three Months Ended September 30, 2018 Net income (loss) $ 200 $ 6 $ 206 Comprehensive income (loss) 206 6 212 Less: Comprehensive income (loss) attributable to noncontrolling interests 72 (1 ) 71 Comprehensive income (loss) attributable to The Williams Companies, Inc. 134 7 141 Nine Months Ended September 30, 2018 Net income (loss) $ 739 $ 11 $ 750 Comprehensive income (loss) 748 11 759 Comprehensive income (loss) attributable to The Williams Companies, Inc. 427 11 438 Consolidated Balance Sheet September 30, 2018 Inventories $ 153 $ (8 ) $ 145 Other current assets and deferred charges 242 (53 ) 189 Total current assets 1,984 (61 ) 1,923 Investments 7,427 (1 ) 7,426 Property, plant, and equipment 39,953 (6 ) 39,947 Property, plant, and equipment – net 28,674 (6 ) 28,668 Intangible assets – net of accumulated amortization 8,324 63 8,387 Regulatory assets, deferred charges, and other 744 (4 ) 740 Total assets 47,153 (9 ) 47,144 Deferred income tax liabilities 1,648 27 1,675 Regulatory liabilities, deferred income, and other 4,376 (159 ) 4,217 Retained deficit (9,018 ) 95 (8,923 ) Total stockholders’ equity 15,610 95 15,705 Noncontrolling interests in consolidated subsidiaries $ 1,349 $ 28 $ 1,377 Total equity 16,959 123 17,082 Total liabilities and equity 47,153 (9 ) 47,144 As Reported Adjustments resulting from adoption of ASC 606 Balance without adoption of ASC 606 (Millions) Consolidated Statement of Changes in Equity September 30, 2018 Adoption of ASC 606 $ (121 ) $ 121 $ — Net income (loss) 739 11 750 Deconsolidation of subsidiary (267 ) (9 ) (276 ) Net increase (decrease) in equity 784 123 907 Balance at September 30, 2018 16,959 123 17,082 |
Variable Interest Entities
Variable Interest Entities | 9 Months Ended |
Sep. 30, 2018 | |
Variable Interest Entity Disclosures [Abstract] | |
Variable Interest Entities [Text Block] | Note 3 – Variable Interest Entities Consolidated VIEs As of September 30, 2018 , we consolidate the following variable interest entities (VIEs): Gulfstar One We own a 51 percent interest in Gulfstar One, a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. Gulfstar One includes a proprietary floating-production system, Gulfstar FPS, and associated pipelines which provide production handling and gathering services in the eastern deepwater Gulf of Mexico. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Gulfstar One’s economic performance. Constitution We own a 41 percent interest in Constitution, a subsidiary that, due to shipper fixed-payment commitments under its long-term firm transportation contracts, is a VIE. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Constitution’s economic performance. We, as operator of Constitution, are responsible for constructing the proposed pipeline connecting its gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems. The total remaining cost of the project is estimated to be approximately $740 million , which would be funded with capital contributions from us and the other equity partners on a proportional basis. In December 2014, Constitution received approval from the FERC to construct and operate its proposed pipeline. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied the necessary water quality certification under Section 401 of the Clean Water Act for the New York portion of the pipeline. In May 2016, Constitution appealed the NYSDEC’s denial of the Section 401 certification to the United States Court of Appeals for the Second Circuit and in August 2017, the court issued a decision denying in part and dismissing in part Constitution’s appeal. The court expressly declined to rule on Constitution’s argument that the delay in the NYSDEC’s decision on Constitution’s Section 401 application constitutes a waiver of the certification requirement. The court determined that it lacked jurisdiction to address that contention and found that jurisdiction over the waiver issue lies exclusively with the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit). As to the denial itself, the court determined that NYSDEC’s action was not arbitrary or capricious. Constitution filed a petition for rehearing with the Second Circuit Court of Appeals, but in October 2017 the court denied our petition. In October 2017, we filed a petition for declaratory order requesting the FERC to find that, by operation of law, the Section 401 certification requirement for the New York State portion of Constitution’s pipeline project was waived due to the failure by the NYSDEC to act on Constitution’s Section 401 application within a reasonable period of time as required by the express terms of such statute. In January 2018, the FERC denied our petition, finding that Section 401 provides that a state waives certification only when it does not act on an application within one year from the date of the application. We filed a request for rehearing of the FERC’s decision, but in July 2018 the FERC denied our request. The project’s sponsors remain committed to the project, and in September 2018 we filed a petition with the D.C. Circuit for review of the FERC’s decision. An unfavorable resolution could result in the impairment of a significant portion of the capitalized project costs, which total $377 million on a consolidated basis at September 30, 2018 , and are included within Property, plant, and equipment in the Consolidated Balance Sheet . Beginning in April 2016, we discontinued capitalization of development costs related to this project. It is also possible that we could incur certain supplier-related costs in the event of a continued prolonged delay or termination of the project. Cardinal We own a 66 percent interest in Cardinal, a subsidiary that provides gathering services for the Utica Shale region and is a VIE due to certain risks shared with customers. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Cardinal’s economic performance. Future expansion activity is expected to be funded with capital contributions from us and the other equity partner on a proportional basis. The following table presents amounts included in our Consolidated Balance Sheet that are for the use or obligation of our consolidated VIEs: September 30, December 31, 2017 (1) Classification (Millions) Assets (liabilities): Cash and cash equivalents $ 32 $ 881 Cash and cash equivalents Trade accounts and other receivables – net 57 972 Trade accounts and other receivables Inventories — 113 Inventories Other current assets 1 176 Other current assets and deferred charges Investments — 6,552 Investments Property, plant, and equipment – net 2,398 27,912 Property, plant, and equipment – net Intangible assets – net 1,189 8,790 Intangible assets – net of accumulated amortization Regulatory assets, deferred charges, and other noncurrent assets — 507 Regulatory assets, deferred charges, and other Accounts payable (16 ) (957 ) Accounts payable Accrued liabilities including current asset retirement obligations (98 ) (857 ) Accrued liabilities Long-term debt due within one year — (501 ) Long-term debt due within one year Long-term debt — (15,996 ) Long-term debt Deferred income tax liabilities — (16 ) Deferred income tax liabilities Noncurrent asset retirement obligations (104 ) (944 ) Regulatory liabilities, deferred income, and other Regulatory liabilities, deferred income, and other noncurrent liabilities (189 ) (2,809 ) Regulatory liabilities, deferred income, and other _________________ (1) Includes WPZ, which was a consolidated VIE at December 31, 2017 (see Note 1 – General, Description of Business, and Basis of Presentation ). Nonconsolidated VIEs Jackalope We own a 50 percent interest in Jackalope, which provides gathering and processing services for the Powder River basin and is a VIE due to certain risks shared with customers. Prior to the second quarter of 2018 we were the primary beneficiary of Jackalope. During the second quarter of 2018, the scope of Jackalope’s planned future activities changed, resulting in a VIE reconsideration event. Upon evaluation, we determined that we are no longer the primary beneficiary, most notably due to changes in the activities that most significantly impact Jackalope’s economic performance and our determination that we do not control the power to direct such activities. These activities are primarily related to the capital decision making process. As a result, we deconsolidated Jackalope on June 30, 2018 and now account for our interest using the equity method of accounting as we exert significant influence over the financial and operational policies of Jackalope (see Note 5 – Investing Activities ). At September 30, 2018 , the carrying value of our investment in Jackalope was $316 million . Our maximum exposure to loss is limited to the carrying value of our investment. Jackalope is undertaking an expansion project that is estimated to cost up to approximately $400 million , which will be funded on a proportional basis. |
Divestitures and Assets Held fo
Divestitures and Assets Held for Sale | 9 Months Ended |
Sep. 30, 2018 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Divestitures and Assets Held for Sale [Text Block] | Note 4 – Divestitures and Assets Held for Sale Divestment of Four Corners Assets On October 1, 2018, we completed the sale of our natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado for total consideration of $1.125 billion , subject to customary working capital adjustments, of which a $113 million deposit was received in the third quarter. At September 30, 2018, these assets were designated as held for sale within the West segment. As a result of this sale, we expect to record a gain of approximately $0.6 billion in the fourth quarter of 2018. The following table presents the carrying amounts of the major classes of the Four Corners area assets and liabilities, which are presented within Assets held for sale and Liabilities held for sale in the Consolidated Balance Sheet: Carrying Amount September 30, 2018 (Millions) Assets: Current assets $ 23 Property, plant, and equipment – net 539 Other noncurrent assets 12 $ 574 Liabilities: Current liabilities $ 22 Other noncurrent liabilities 23 $ 45 The following table presents the results of operations for the Four Corners area: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (Millions) Income (loss) before income taxes of Four Corners area $ 25 $ 14 $ 52 $ 31 Income (loss) before income taxes of Four Corners area attributable to The Williams Companies, Inc. 23 10 43 23 Other Assets Held for Sale Certain assets and operations from our former petchem services are designated as held for sale within the Atlantic-Gulf and Other segments as of September 30, 2018. Included as part of the disposal group and presented within Assets held for sale and Liabilities held for sale in the Consolidated Balance Sheet, are Current assets and Property, plant, and equipment - net, of approximately $2 million and $84 million , respectively, and Current liabilities and Noncurrent liabilities of approximately $1 million and $3 million , respectively. Assets held for sale also includes certain other insignificant assets unrelated to these disposal groups. Divestment of Geismar Interest In July 2017, we completed the sale of Williams Olefins, L.L.C., a wholly owned subsidiary which owned our Geismar Interest for total consideration of $2.084 billion in cash. We received a final working capital adjustment of $12 million in October 2017. Upon closing of the sale, we entered into a long-term supply and transportation agreement with the purchaser to provide feedstock to the plant via our Bayou Ethane pipeline system. As a result of this sale, we recorded a gain of $1.095 billion in the third quarter of 2017 in our Other segment. Following this sale, the cash proceeds were used to repay our $850 million term loan. Proceeds were also used to fund a portion of the capital and investment expenditures that were a part of our growth portfolio. The following table presents the results of operations for the Geismar Interest, excluding the gain noted above: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (Millions) Income (loss) before income taxes of the Geismar Interest $ — $ 1 $ — $ 26 Income (loss) before income taxes of the Geismar Interest attributable to The Williams Companies, Inc. — 1 — 19 |
Investing Activities
Investing Activities | 9 Months Ended |
Sep. 30, 2018 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Investing Activities [Text Block] | Note 5 – Investing Activities RMM Equity-Method Investment During the third quarter of 2018, our joint venture, RMM, purchased a natural gas and oil gathering and natural gas processing business in Colorado’s Denver-Julesburg basin. Our initial economic ownership was 40 percent , which is expected to increase to 50 percent as we provide additional capital contributions. At September 30, 2018, our carrying value was $569 million reflecting our 43 percent economic ownership. We are committed to fund up to an additional $177 million to reach 50 percent economic ownership, to the extent RMM needs funding for capital expenditures. We account for this investment under the equity method of accounting. Jackalope Deconsolidation During the second quarter of 2018, we deconsolidated our interest in Jackalope (see Note 3 – Variable Interest Entities ). We recorded our interest in Jackalope as an equity-method investment at its estimated fair value, resulting in a deconsolidation gain of $62 million reflected in Other investing income (loss) – net in the Consolidated Statement of Income . We estimated the fair value of our interest to be $310 million using an income approach based on expected future cash flows and an appropriate discount rate (a Level 3 measurement within the fair value hierarchy). The determination of expected future cash flows involved significant assumptions regarding gathering and processing volumes and related capital spending. A 10.9 percent discount rate was utilized and reflected our estimate of the cost of capital as impacted by market conditions and risks associated with the underlying business. The deconsolidated carrying value of the net assets of Jackalope included $47 million of goodwill. Acquisition of Additional Interests in Appalachia Midstream Investments During the first quarter of 2017, we exchanged all of our 50 percent interest in DBJV for an increased interest in two natural gas gathering systems that are part of the Appalachia Midstream Investments and $155 million in cash. This transaction was recorded based on our estimate of the fair value of the interests received as we have more insight to this value as we operate the underlying assets. Following this exchange, we have an approximate average 66 percent interest in the Appalachia Midstream Investments. We continue to account for this investment under the equity method of accounting due to the significant participatory rights of our partners such that we do not exercise control. We also sold all of our interest in Ranch Westex JV LLC for $45 million . These transactions resulted in a total gain of $269 million reflected in Other investing income (loss) – net in the Consolidated Statement of Income . The fair value of the increased interests in the Appalachia Midstream Investments received as consideration was estimated to be $1.1 billion using an income approach based on expected cash flows and an appropriate discount rate (a Level 3 measurement within the fair value hierarchy). The determination of estimated future cash flows involved significant assumptions regarding gathering volumes, rates, and related capital spending. A 9.5 percent discount rate was utilized and reflected our estimate of the cost of capital as impacted by market conditions and risks associated with the underlying business. |
Other Income and Expenses
Other Income and Expenses | 9 Months Ended |
Sep. 30, 2018 | |
Other Income and Expenses [Abstract] | |
Other Income and Expenses [Text Block] | Note 6 – Other Income and Expenses The following table presents certain gains or losses reflected in Other (income) expense – net within Costs and expenses in our Consolidated Statement of Income : Three Months Ended Nine Months Ended 2018 2017 2018 2017 (Millions) Atlantic-Gulf Amortization of regulatory assets associated with asset retirement obligations $ 8 $ 8 $ 24 $ 25 Accrual of regulatory liability related to overcollection of certain employee expenses 5 5 16 16 Project development costs related to Constitution (see Note 3) 1 4 4 12 Adjustments to regulatory liability related to Tax Reform — — (10 ) — Gain on asset retirement (10 ) (5 ) (10 ) (5 ) West Gains on contract settlements and terminations — — — (15 ) Adjustments to regulatory liability related to Tax Reform — — (7 ) — Regulatory charge per approved rates related to Tax Reform 6 — 18 — Charge for regulatory liability associated with the decrease in Northwest Pipeline’s estimated deferred state income tax rates following WPZ Merger 12 — 12 — Other Benefit of regulatory asset associated with increase in Transco’s estimated deferred state income tax rate following WPZ Merger (37 ) — (37 ) — Gain on sale of Refinery Grade Propylene Splitter — — — (12 ) Additional Items Certain additional items included in the Consolidated Statement of Income are as follows: • Selling, general, and administrative expenses for the three and nine months ended September 30, 2018 includes a $35 million charge associated with a charitable contribution of preferred stock to The Williams Companies Foundation, Inc. (a not-for-profit corporation) within the Other segment. (See Note 11 – Stockholders’ Equity .) Selling, general, and administrative expenses for the three and nine months ended September 30, 2018 also includes $15 million and $19 million , respectively, for WPZ Merger related costs within the Other segment. Selling, general, and administrative expenses for the three and nine months ended September 30, 2017 includes $5 million and $18 million , respectively, of severance and other related costs within the Other segment. • Other income (expense) – net below Operating income (loss) includes income of $33 million and $80 million for the three and nine months ended September 30, 2018 , respectively, and $17 million and $55 million for the three and nine months ended September 30, 2017 , respectively, for allowance for equity funds used during construction primarily within the Atlantic-Gulf segment. Other income (expense) – net below Operating income (loss) also includes income of $22 million and $31 million for the three and nine months ended September 30, 2018 , respectively, and $8 million and $44 million for the three and nine months ended September 30, 2017 , respectively of income associated with a regulatory asset related to deferred taxes on equity funds used during construction. These items are reported primarily within the Other segment. • Other income (expense) – net below Operating income (loss) for the nine months ended September 30, 2018 , includes a $7 million net loss associated with the March 28, 2018, early retirement of $750 million of 4.875 percent senior unsecured notes that were due in 2024. The net loss within the Other segment reflects $34 million in premiums paid, partially offset by $27 million of unamortized premium. (See Note 10 – Debt and Banking Arrangements .) Other income (expense) – net below Operating income (loss) for the three months ended September 30, 2017 includes a net loss of $3 million associated with the July 3, 2017 early retirement of $1.4 billion of 4.875 percent senior unsecured notes that were due in 2023. The net loss for the July 3, 2017 early retirement reflects $54 million in premiums paid, offset by $51 million of unamortized premium. For the nine months ended September 30, 2017 , Other income (expense) – net below Operating income (loss) also includes a net gain of $30 million associated with the February 23, 2017, early retirement of $750 million of 6.125 percent senior unsecured notes that were due in 2022. The net gain within the Other segment reflects $53 million of unamortized premium, partially offset by $23 million in premiums paid. |
Provision (Benefit) for Income
Provision (Benefit) for Income Taxes | 9 Months Ended |
Sep. 30, 2018 | |
Income Tax Disclosure [Abstract] | |
Provision (Benefit) for Income Taxes [Text Block] | Note 7 – Provision (Benefit) for Income Taxes The Provision (benefit) for income taxes includes: Three Months Ended Nine Months Ended 2018 2017 2018 2017 (Millions) Current: Federal $ (19 ) $ 7 $ (55 ) $ 10 State — 9 1 17 (19 ) 16 (54 ) 27 Deferred: Federal 188 (11 ) 312 63 State 21 19 39 36 209 8 351 99 Provision (benefit) for income taxes $ 190 $ 24 $ 297 $ 126 The effective income tax rates for the total provision for the three and nine months ended September 30, 2018 , are higher than the federal statutory rate primarily due to the effect of state income taxes and a $105 million valuation allowance associated with foreign tax credits, that expire between 2024 and 2027. This is partially offset by the impact of the allocation of income to nontaxable noncontrolling interests. The state income tax provisions include a $38 million provision related to an increase in the deferred state income tax rate (net of federal benefit) partially offset by a net decrease in valuation allowances of $31 million on state net operating losses, both primarily driven by the impact that the completion of the WPZ Merger (see Note 1 – General, Description of Business, and Basis of Presentation ) had on income allocation for state tax purposes. A valuation allowance for deferred tax assets, including foreign tax credits, is recognized when it is more likely than not that some, or all, of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our sources of future taxable income, including available tax planning strategies, to determine whether a valuation allowance is required. The completion of the WPZ Merger decreased our deferred income tax liability by $1.829 billion . Increased tax depreciation from the additional tax basis will reduce taxable income in future years and may limit our ability to realize the full benefit of certain short-lived deferred tax assets. The effective income tax rate for the three months ended September 30, 2017 , is less than the federal statutory rate primarily due to the impact of the allocation of income to nontaxable noncontrolling interests, partially offset by the effect of state income taxes, including an $18 million provision related to an increase in the deferred state income tax rate (net of federal benefit). The effective income tax rate for the nine months ended September 30, 2017 , is less than the federal statutory rate. This is primarily due to the impact of the allocation of income to nontaxable noncontrolling interests and releasing a $127 million valuation allowance on a deferred tax asset associated with a capital loss carryover, partially offset by the effect of state income taxes, including an $18 million provision related to an increase in the deferred state income tax rate (net of federal benefit). In 2016, we recorded a valuation allowance on a deferred tax asset associated with a capital loss that was incurred with the sale of our Canadian operations. The sale of the Geismar olefins facility in 2017 (see Note 4 – Divestitures and Assets Held for Sale ) generated capital gains sufficient to offset the capital loss carryover, thereby allowing us to reverse the valuation allowance in full. On December 22, 2017, Tax Reform was enacted. Under the guidance provided by Securities and Exchange Commission Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act, we recorded provisional adjustments related to the impact of Tax Reform in the fourth quarter of 2017. We consider all amounts recorded related to Tax Reform to be reasonable estimates. The amounts recorded continue to be provisional as our interpretation, assessment, and presentation of the impact of the tax law change may be further clarified with additional guidance from regulatory, tax, and accounting authorities. We anticipate that additional guidance from the Internal Revenue Service will be released to guide us in determining what assets are eligible for direct expensing. We are also recording provisional adjustments for valuation allowances associated with losses and credits since, at this time, we cannot assess the impact that the interest expense disallowance will have on our estimated future taxable income. We are not reducing our minimum tax credit for sequestration until we receive further guidance provided by these authorities or other sources. During the next 12 months, we do not expect ultimate resolution of any unrecognized tax benefit associated with domestic or international matters to have a material impact on our unrecognized tax benefit position. |
Earnings Per Common Share
Earnings Per Common Share | 9 Months Ended |
Sep. 30, 2018 | |
Earnings Per Share [Abstract] | |
Earnings Per Common Share [Text Block] | Note 8 – Earnings Per Common Share Three Months Ended Nine Months Ended 2018 2017 2018 2017 (Dollars in millions, except per-share amounts; shares in thousands) Net income available to common stockholders $ 129 $ 33 $ 416 $ 487 Basic weighted-average shares 1,023,587 826,779 893,706 825,925 Effect of dilutive securities: Nonvested restricted stock units 2,387 1,889 2,102 1,567 Stock options 530 700 514 658 Diluted weighted-average shares 1,026,504 829,368 896,322 828,150 Earnings per common share: Basic $ .13 $ .04 $ .47 $ .59 Diluted $ .13 $ .04 $ .46 $ .59 |
Employee Benefit Plans
Employee Benefit Plans | 9 Months Ended |
Sep. 30, 2018 | |
Retirement Benefits [Abstract] | |
Employee Benefit Plans [Text Block] | Note 9 – Employee Benefit Plans Net periodic benefit cost (credit) is as follows: Pension Benefits Three Months Ended Nine Months Ended 2018 2017 2018 2017 (Millions) Components of net periodic benefit cost (credit): Service cost $ 12 $ 13 $ 37 $ 38 Interest cost 12 15 35 44 Expected return on plan assets (16 ) (21 ) (47 ) (62 ) Amortization of net actuarial loss 6 6 17 20 Net actuarial loss from settlements 1 — 2 — Net periodic benefit cost (credit) $ 15 $ 13 $ 44 $ 40 Other Postretirement Benefits Three Months Ended Nine Months Ended 2018 2017 2018 2017 (Millions) Components of net periodic benefit cost (credit): Service cost $ 1 $ — $ 1 $ 1 Interest cost 1 2 5 6 Expected return on plan assets (2 ) (3 ) (8 ) (9 ) Amortization of prior service credit — (3 ) (1 ) (10 ) Reclassification to regulatory liability — 1 1 3 Net periodic benefit cost (credit) $ — $ (3 ) $ (2 ) $ (9 ) The components of Net periodic benefit cost (credit) other than the Service cost component are included in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Income . Amortization of prior service credit included in Net periodic benefit cost (credit) for our other postretirement benefit plans associated with Transco and Northwest Pipeline is recorded to regulatory assets/liabilities instead of O ther comprehensive income (loss). The amounts of Amortization of prior service credit recognized in regulatory liabilities were $2 million for the three months ended September 30, 2017 , and $1 million and $6 million for the nine months ended September 30, 2018 and 2017 , respectively. During the nine months ended September 30, 2018 , we contributed $87 million to our pension plans and $4 million to our other postretirement benefit plans. We presently anticipate making additional contributions of approximately $1 million to our pension plans and approximately $2 million to our other postretirement benefit plans in the remainder of 2018. |
Debt and Banking Arrangements
Debt and Banking Arrangements | 9 Months Ended |
Sep. 30, 2018 | |
Debt Disclosure [Abstract] | |
Debt and Banking Arrangements [Text Block] | Note 10 – Debt and Banking Arrangements Long-Term Debt Issuances and retirements On August 24, 2018, Northwest Pipeline issued $250 million of 4 percent senior unsecured notes to investors in a private debt placement. The notes are an additional issuance of Northwest Pipeline’s existing 4 percent senior unsecured notes due 2027. As part of the issuance, Northwest Pipeline entered into a registration rights agreement with the initial purchasers of the unsecured notes. Northwest Pipeline is obligated to file and consummate a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act of 1933, as amended, within 365 days from closing and to use commercially reasonable efforts to complete the exchange offer. Northwest Pipeline is required to provide a shelf registration statement to cover resales of the notes under certain circumstances. If Northwest Pipeline fails to fulfill these obligations, additional interest will accrue on the affected securities. The rate of additional interest will be 0.25 percent per annum on the principal amount of the affected securities for the first 90-day period immediately following the occurrence of a registration default, increasing by an additional 0.25 percent per annum with respect to each subsequent 90-day period thereafter, up to a maximum amount for all such registration defaults of 0.5 percent annually. Following the cure of any registration defaults, the accrual of additional interest will cease. Northwest Pipeline retired $250 million of 6.05 percent senior unsecured notes that matured on June 15, 2018. On March 5, 2018, WPZ completed a public offering of $800 million of 4.85 percent senior unsecured notes due 2048. WPZ used the net proceeds for general partnership purposes, primarily the March 28, 2018 repayment of $750 million of 4.875 percent senior unsecured notes that were due in 2024. On March 15, 2018, Transco issued $400 million of 4 percent senior unsecured notes due 2028 and $600 million of 4.6 percent senior unsecured notes due 2048 to investors in a private debt placement. Transco used the net proceeds to retire $250 million of 6.05 percent senior unsecured notes that matured on June 15, 2018, and for general corporate purposes, including the funding of capital expenditures. In September 2018, Transco completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended. Other financing obligations During the first three quarters of 2018, Transco received an additional $29 million of funding from a co-owner related to the construction of the Dalton expansion project. This additional funding is reflected as Long-term debt in the Consolidated Balance Sheet . During the construction of the Atlantic Sunrise project, Transco received funding from a partner for its proportionate share of construction costs related to an undivided ownership interest in certain parts of the project. Amounts received were recorded within noncurrent liabilities and 100 percent of the costs associated with construction were capitalized in our Consolidated Balance Sheet. Upon placing the project in service during October 2018, Transco began utilizing this partner’s undivided interest in the lateral, including the associated pipeline capacity, and expects to reclassify approximately $790 million of funding previously received from its partner from noncurrent liabilities to debt to reflect the financing obligation payable to its partner over an expected term of 20 years . As this transaction did not meet the criteria for sale leaseback accounting due to our continued involvement, it will be accounted for as a financing arrangement over the course of the capacity agreement. Commercial Paper Program On August 10, 2018, following the consummation of the WPZ Merger, WPZ’s $3 billion commercial paper program was discontinued and we entered into a new $4 billion commercial paper program. The maturities of the commercial paper notes vary but may not exceed 397 days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or, alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. The net proceeds of issuances of the commercial paper notes are expected to be used to fund planned capital expenditures and for other general corporate purposes. At September 30, 2018, approximately $824 million of Commercial paper at a weighted-average interest rate of 2.73 percent was outstanding. At October 30, 2018, no commercial paper was outstanding. Credit Facilities September 30, 2018 Stated Capacity Outstanding (Millions) Long-term credit facility (1) $ 4,500 $ — Letters of credit under certain bilateral bank agreements 14 (1) In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. Revolving credit facility On July 13, 2018, we along with Transco and Northwest Pipeline, the lenders named therein, and an administrative agent entered into a new credit agreement (Credit Agreement) with aggregate commitments available of $4.5 billion , with up to an additional $500 million increase in aggregate commitments available under certain circumstances. On August 10, 2018, following the completion of the WPZ Merger, the Credit Agreement became effective and we terminated both our and WPZ’s existing credit facilities. The maturity date of the new credit facility is August 10, 2023. However, the co-borrowers may request up to two extensions of the maturity date each for an additional one-year period to allow a maturity date as late as August 10, 2025, under certain circumstances. The Credit Agreement allows for swing line loans up to an aggregate of $200 million , subject to available capacity under the new credit facility, and letters of credit commitments of $1 billion . Transco and Northwest Pipeline are each able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers. The Credit Agreement contains the following terms and conditions: • Various covenants may limit, among other things, a borrower's and its material subsidiaries' ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, make certain distributions during an event of default, and enter into certain restrictive agreements. • If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to terminate the commitments and accelerate the maturity of the loans and exercise other rights and remedies. • Other than swing line loans, each time funds are borrowed, the applicable borrower may choose from two methods of calculating interest: a fluctuating base rate equal to Citibank N.A.'s adjusted base rate plus an applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate plus an applicable margin. We are required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined by reference to a pricing schedule based on the applicable borrower’s senior unsecured long-term debt ratings. Significant financial covenants under the Credit Agreement require the ratio of debt to EBITDA (earnings before interest, taxes, depreciation, and amortization), each as defined in the credit facility, to be no greater than: • 5.75 to 1 for each fiscal quarter end through June 30, 2019; • 5.5 to 1 for the fiscal quarters ending September 30, 2019, and December 31, 2019; • 5.0 to 1 for the fiscal quarter ending March 31, 2020, and each subsequent fiscal quarter end, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions with a total aggregate purchase price of $25 million or more has been executed, in which case the ratio of debt to EBITDA is to be no greater than 5.5 to 1. The ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent for each of Transco and Northwest Pipeline. At September 30, 2018, we are in compliance with these covenants. |
Stockholders' Equity
Stockholders' Equity | 9 Months Ended |
Sep. 30, 2018 | |
Stockholders' Equity Note [Abstract] | |
Stockholders' Equity [Text Block] | Note 11 – Stockholders’ Equity Issuance of Preferred Shares In July 2018, through a wholly owned subsidiary, we contributed 35,000 shares of newly issued Series B Non-Voting Perpetual Preferred Stock (Preferred Stock) to The Williams Companies Foundation, Inc. (a not-for-profit corporation) for use in future charitable and nonprofit causes. The charitable contribution of Preferred Stock was recorded as an expense in the third quarter of 2018. The Preferred Stock was issued for an aggregate value of $35 million and pays non-cumulative quarterly cash dividends when, as and if declared, at a rate of 7.25 percent per year. We paid dividends totaling $0.4 million on the shares of Preferred Stock in September 2018. Our certificate of incorporation authorizes 30 million shares of Preferred Stock, $1 par value per share. AOCI The following table presents the changes in Accumulated other comprehensive income (loss) (AOCI) by component, net of income taxes: Cash Flow Hedges Foreign Currency Translation Pension and Other Postretirement Benefits Total (Millions) Balance at December 31, 2017 $ (2 ) $ (1 ) $ (235 ) $ (238 ) Adoption of ASU 2018-02 (Note 1) — — (61 ) (61 ) WPZ Merger (Note 1) (3 ) — — (3 ) Other comprehensive income (loss): Other comprehensive income (loss) before reclassifications (14 ) — 4 (10 ) Amounts reclassified from accumulated other comprehensive income (loss) 7 — 14 21 Other comprehensive income (loss) (7 ) — 18 11 Balance at September 30, 2018 $ (12 ) $ (1 ) $ (278 ) $ (291 ) Reclassifications out of AOCI are presented in the following table by component for the nine months ended September 30, 2018 : Component Reclassifications Classification (Millions) Cash flow hedges: Energy commodity contracts $ 13 Product sales Pension and other postretirement benefits: Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit) 19 Note 9 – Employee Benefit Plans Total before tax 32 Income tax benefit (8 ) Provision (benefit) for income taxes Net of income tax 24 Noncontrolling interest (3 ) Net income (loss) attributable to noncontrolling interests Reclassifications during the period $ 21 |
Fair Value Measurements and Gua
Fair Value Measurements and Guarantees | 9 Months Ended |
Sep. 30, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements and Guarantees [Text Block] | Note 12 – Fair Value Measurements and Guarantees The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, commercial paper, and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table. Fair Value Measurements Using Carrying Amount Fair Value Quoted Prices In Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (Millions) Assets (liabilities) at September 30, 2018: Measured on a recurring basis: ARO Trust investments $ 157 $ 157 $ 157 $ — $ — Energy derivatives assets not designated as hedging instruments 6 6 6 — — Energy derivatives liabilities designated as hedging instruments (14 ) (14 ) (13 ) (1 ) — Energy derivatives liabilities not designated as hedging instruments (9 ) (9 ) (6 ) — (3 ) Additional disclosures: Other receivables 21 21 21 — — Long-term debt, including current portion (21,442 ) (22,532 ) — (22,532 ) — Guarantees (43 ) (30 ) — (14 ) (16 ) Assets (liabilities) at December 31, 2017: Measured on a recurring basis: ARO Trust investments $ 135 $ 135 $ 135 $ — $ — Energy derivatives liabilities designated as hedging instruments (3 ) (3 ) (2 ) (1 ) — Energy derivatives liabilities not designated as hedging instruments (3 ) (3 ) — — (3 ) Additional disclosures: Other receivables 7 7 7 — — Long-term debt, including current portion (20,935 ) (23,005 ) — (23,005 ) — Guarantees (43 ) (30 ) — (14 ) (16 ) Fair Value Methods We use the following methods and assumptions in estimating the fair value of our financial instruments: Assets and liabilities measured at fair value on a recurring basis ARO Trust investments : Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into an external trust (ARO Trust) that is specifically designated to fund future asset retirement obligations (ARO). The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market and is reported in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. Energy derivatives : Energy derivatives include commodity-based exchange-traded contracts and over-the-counter contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Energy derivatives assets are reported in Other current assets and deferred charges and Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Energy derivatives liabilities are reported in Accrued liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet. Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the nine months ended September 30, 2018 or 2017 . Additional fair value disclosures Other receivables: Other receivables consist of margin deposits, which are reported in Other current assets and deferred charges in the Consolidated Balance Sheet. The disclosed fair value of our margin deposits is considered to approximate the carrying value generally due to the short-term nature of these items. Long-term debt, including current portion : The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. Guarantees : Guarantees primarily consist of a guarantee we have provided in the event of nonpayment by our previously owned communications subsidiary, Williams Communications Group (WilTel), on a lease performance obligation that extends through 2042. Guarantees also include an indemnification related to a disposed operation. To estimate the fair value of the WilTel guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rate is published by Moody’s Investors Service. The carrying value of the WilTel guarantee is reported in Accrued liabilities in the Consolidated Balance Sheet. The maximum potential undiscounted exposure is approximately $29 million at September 30, 2018 . Our exposure declines systematically through the remaining term of WilTel’s obligation. The fair value of the guarantee associated with the indemnification related to a disposed operation was estimated using an income approach that considered probability-weighted scenarios of potential levels of future performance. The terms of the indemnification do not limit the maximum potential future payments associated with the guarantee. The carrying value of this guarantee is reported in Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet. We are required by our revolving credit agreement to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have no carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim. Nonrecurring fair value measurements The following table presents impairments of assets associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy, except as specifically noted. Impairments Nine Months Ended September 30, Classification Segment Date of Measurement Fair Value 2018 2017 (Millions) Certain idle pipeline assets (1) Property, plant, and equipment – net Other June 30, 2018 $ 25 $ 66 Certain gathering operations (2) Property, plant, and equipment – net and Intangible assets - net of accumulated amortization West September 30, 2017 439 $ 1,019 Certain gathering operations (3) Property, plant, and equipment – net and Intangible assets - net of accumulated amortization Northeast G&P September 30, 2017 21 115 Certain NGL pipeline (4) Property, plant, and equipment – net Other September 30, 2017 32 68 Certain olefins pipeline project (5) Property, plant, and equipment – net Other June 30, 2017 18 23 Fair value measurements of certain assets 66 1,225 Other impairments and write-downs (6) — 11 Impairment of certain assets $ 66 $ 1,236 _______________ (1) Relates to certain idle pipelines. The estimated fair value was determined by a market approach incorporating information derived from bids received for these assets, which are currently being marketed for sale together with certain other assets. These inputs result in a fair value measurement within Level 2 of the fair value hierarchy. (2) Relates to certain gathering operations in the Mid-Continent region. During the third quarter of 2017, we received solicitations and engaged in negotiations for the sale of certain of these assets which led to our impairment evaluation. The estimated fair value was determined using an income approach and incorporated market inputs based on ongoing negotiations for a potential sale of a portion of the underlying assets. For the income approach, we utilized a discount rate of 10.2 percent , reflecting an estimated cost of capital and risks associated with the underlying assets. (3) Relates to certain gathering operations in the Marcellus South region resulting from an anticipated decline in future volumes following a third-quarter 2017 shut-in by the primary producer. The estimated fair value was determined by the income approach utilizing a discount rate of 11.1 percent , reflecting an estimated cost of capital and risks associated with the underlying assets. (4) Relates to an NGL pipeline near the Houston Ship Channel region which we anticipate will be underutilized for the foreseeable future. The estimated fair value was primarily determined by using a market approach based on our analysis of observable inputs in the principal market. (5) Relates primarily to project development costs associated with an olefins pipeline project in the Gulf Coast region, the likelihood of completion of which is now considered remote. The estimated fair value of the remaining pipe and equipment considered a market approach based on our analysis of observable inputs in the principal market, as well as an estimate of replacement cost. (6) Reflects multiple individually insignificant impairments and write-downs of other certain assets that may no longer be in use or are surplus in nature for which the fair value was determined to be lower than the carrying value. |
Contingent Liabilities
Contingent Liabilities | 9 Months Ended |
Sep. 30, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Contingent Liabilities [Text Block] | Note 13 – Contingent Liabilities Reporting of Natural Gas-Related Information to Trade Publications Direct and indirect purchasers of natural gas in various states filed individual and class actions against us, our former affiliate WPX Energy, Inc. (WPX) and its subsidiaries, and others alleging the manipulation of published gas price indices and seeking unspecified amounts of damages. Such actions were transferred to the Nevada federal district court for consolidation of discovery and pre-trial issues. We have agreed to indemnify WPX and its subsidiaries related to this matter. In the individual action, filed by Farmland Industries Inc. (Farmland), the court issued an order on May 24, 2016, granting one of our co-defendant’s motion for summary judgment as to Farmland’s claims. On January 5, 2017, the court extended such ruling to us, entering final judgment in our favor. Farmland appealed. On March 27, 2018, the appellate court reversed the district court’s grant of summary judgment, and on April 10, 2018, the defendants filed a petition for rehearing with the appellate court, which was denied on May 9, 2018. The case has been remanded to the Nevada federal district court. In the putative class actions, on March 30, 2017, the court issued an order denying the plaintiffs’ motions for class certification. On June 13, 2017, the United States Court of Appeals for the Ninth Circuit granted the plaintiffs’ petition for permission to appeal the order. On August 6, 2018, the Ninth Circuit reversed the order denying class certification and remanded the case to the Nevada federal district court. Because of the uncertainty around the remaining pending unresolved issues, we cannot reasonably estimate a range of potential exposure at this time. However, it is reasonably possible that the ultimate resolution of these actions and our related indemnification obligation could result in a potential loss that may be material to our results of operations. In connection with this indemnification, we have an accrued liability balance associated with this matter, and as a result, have exposure to future developments. Alaska Refinery Contamination Litigation We are involved in litigation arising from our ownership and operation of the North Pole Refinery in North Pole, Alaska, from 1980 until 2004, through our wholly owned subsidiaries, Williams Alaska Petroleum Inc. (WAPI) and MAPCO Inc. We sold the refinery to Flint Hills Resources Alaska, LLC (FHRA), a subsidiary of Koch Industries, Inc., in 2004. The litigation involves three cases, with filing dates ranging from 2010 to 2014. The actions arise from sulfolane contamination allegedly emanating from the refinery. A putative class action lawsuit was filed by James West in 2010 naming us, WAPI, and FHRA as defendants. We and FHRA filed claims against each other seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination. In 2011, we and FHRA settled the claim with James West. Certain claims by FHRA against us were resolved by the Alaska Supreme Court in our favor. FHRA’s claims against us for contractual indemnification and statutory claims for damages related to off-site sulfolane remain pending. The State of Alaska filed its action in March 2014, seeking damages. The City of North Pole (North Pole) filed its lawsuit in November 2014, seeking past and future damages, as well as punitive damages. Both we and WAPI asserted counterclaims against the State of Alaska and North Pole, and cross-claims against FHRA. FHRA has also filed cross-claims against us. The underlying factual basis and claims in the cases are similar and may duplicate exposure. As such, in February 2017, the three cases were consolidated into one action in state court containing the remaining claims from the James West case and those of the State of Alaska and North Pole. A trial encompassing all three cases was originally scheduled to commence in May 2017 but has been rescheduled for March 2019. Due to the ongoing assessment of the level and extent of sulfolane contamination, the lack of an articulated cleanup level for sulfolane, and the lack of a concrete remedial proposal and cost estimate, we are unable to estimate a range of exposure to the State of Alaska or North Pole at this time. We currently estimate that our reasonably possible loss exposure to FHRA could range from an insignificant amount up to $32 million , although uncertainties inherent in the litigation process, expert evaluations, and jury dynamics might cause our exposure to exceed that amount. Independent of the litigation matter described in the preceding paragraphs, in 2013, the Alaska Department of Environmental Conservation indicated that it views FHRA and us as responsible parties, and that it intends to enter a compliance order to address the environmental remediation of sulfolane and other possible contaminants including cleanup work outside the refinery’s boundaries. To date, no compliance order has been issued. Due to the ongoing assessment of the level and extent of sulfolane contamination, the ultimate cost of remediation and division of costs among the potentially responsible parties, and the previously described separate litigation, we are unable to estimate a range of exposure at this time. Royalty Matters Certain of our customers, including one major customer, have been named in various lawsuits alleging underpayment of royalties and claiming, among other things, violations of anti-trust laws and the Racketeer Influenced and Corrupt Organizations Act. We have also been named as a defendant in certain of these cases filed in Pennsylvania based on allegations that we improperly participated with that major customer in causing the alleged royalty underpayments. We believe that the claims asserted are subject to indemnity obligations owed to us by that major customer. That customer has reached a tentative settlement to resolve substantially all Pennsylvania royalty cases pending, which settlement would apply to both the customer and us. The settlement as reported would not require any contribution from us. Litigation Against Energy Transfer and Related Parties On April 6, 2016, we filed suit in Delaware Chancery Court against Energy Transfer Equity, L.P. (Energy Transfer) and LE GP, LLC (the general partner for Energy Transfer) alleging willful and material breaches of the Agreement and Plan of Merger (ETE Merger Agreement) with Energy Transfer resulting from the private offering by Energy Transfer on March 8, 2016, of Series A Convertible Preferred Units (Special Offering) to certain Energy Transfer insiders and other accredited investors. The suit seeks, among other things, an injunction ordering the defendants to unwind the Special Offering and to specifically perform their obligations under the ETE Merger Agreement. On April 19, 2016, we filed an amended complaint seeking the same relief. On May 3, 2016, Energy Transfer and LE GP, LLC filed an answer and counterclaims. On May 13, 2016, we filed a separate complaint in Delaware Chancery Court against Energy Transfer, LE GP, LLC, and the other Energy Transfer affiliates that are parties to the ETE Merger Agreement, alleging material breaches of the ETE Merger Agreement for failing to cooperate and use necessary efforts to obtain a tax opinion required under the ETE Merger Agreement (Tax Opinion) and for otherwise failing to use necessary efforts to consummate the merger under the ETE Merger Agreement wherein we would be merged with and into the newly formed Energy Transfer Corp LP (ETC) (ETC Merger). The suit sought, among other things, a declaratory judgment and injunction preventing Energy Transfer from terminating or otherwise avoiding its obligations under the ETE Merger Agreement due to any failure to obtain the Tax Opinion. The Court of Chancery coordinated the Special Offering and Tax Opinion suits. On May 20, 2016, the Energy Transfer defendants filed amended affirmative defenses and verified counterclaims in the Special Offering and Tax Opinion suits, alleging certain breaches of the ETE Merger Agreement by us and seeking, among other things, a declaration that we were not entitled to specific performance, that Energy Transfer could terminate the ETC Merger, and that Energy Transfer is entitled to a $1.48 billion termination fee. On June 24, 2016, following a two-day trial, the court issued a Memorandum Opinion and Order denying our requested relief in the Tax Opinion suit. The court did not rule on the substance of our claims related to the Special Offering or on the substance of Energy Transfer’s counterclaims. On June 27, 2016, we filed an appeal of the court’s decision with the Supreme Court of Delaware, seeking reversal and remand to pursue damages. On March 23, 2017, the Supreme Court of Delaware affirmed the Court of Chancery’s ruling. On March 30, 2017, we filed a motion for reargument with the Supreme Court of Delaware, which was denied on April 5, 2017. On September 16, 2016, we filed an amended complaint with the Court of Chancery seeking damages for breaches of the ETE Merger Agreement by defendants. On September 23, 2016, Energy Transfer filed a second amended and supplemental affirmative defenses and verified counterclaim with the Court of Chancery seeking, among other things, payment of the $1.48 billion termination fee due to our alleged breaches of the ETE Merger Agreement. On December 1, 2017, the court granted our motion to dismiss certain of Energy Transfer’s counterclaims, including its claim seeking payment of the $1.48 billion termination fee. On December 8, 2017, Energy Transfer filed a motion for reargument, which the Court of Chancery denied on April 16, 2018. The Court of Chancery scheduled trial for May 20 through May 24, 2019. Environmental Matters We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of September 30, 2018 , we have accrued liabilities totaling $36 million for these matters, as discussed below. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. At September 30, 2018 , certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors. The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. These rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, air quality standards for one-hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. On October 1, 2015, the EPA issued its rule regarding National Ambient Air Quality Standards for ground-level ozone, setting a stricter standard of 70 parts per billion . We are monitoring the rule’s implementation as the reduction will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net in the Consolidated Balance Sheet for both new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance. Continuing operations Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At September 30, 2018 , we have accrued liabilities of $7 million for these costs. We expect that these costs will be recoverable through rates. We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At September 30, 2018 , we have accrued liabilities totaling $7 million for these costs. Former operations, including operations classified as discontinued We have potential obligations in connection with assets and businesses we no longer operate. These potential obligations include remediation activities at the direction of federal and state environmental authorities and the indemnification of the purchasers of certain of these assets and businesses for environmental and other liabilities existing at the time the sale was consummated. Our responsibilities relate to the operations of the assets and businesses described below. • Former agricultural fertilizer and chemical operations and former retail petroleum and refining operations; • Former petroleum products and natural gas pipelines; • Former petroleum refining facilities; • Former exploration and production and mining operations; • Former electricity and natural gas marketing and trading operations. At September 30, 2018 , we have accrued environmental liabilities of $22 million related to these matters. Other Divestiture Indemnifications Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, property damage, environmental matters, right of way, and other representations that we have provided. At September 30, 2018 , other than as previously disclosed, we are not aware of any material claims against us involving the indemnities; thus, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. Any claim for indemnity brought against us in the future may have a material adverse effect on our results of operations in the period in which the claim is made. In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations, none of which are expected to be material to our expected future annual results of operations, liquidity, and financial position. Summary We have disclosed our estimated range of reasonably possible losses for certain matters above, as well as all significant matters for which we are unable to reasonably estimate a range of possible loss. We estimate that for all other matters for which we are able to reasonably estimate a range of loss, our aggregate reasonably possible losses beyond amounts accrued are immaterial to our expected future annual results of operations, liquidity, and financial position. These calculations have been made without consideration of any potential recovery from third parties. |
Segment Disclosures
Segment Disclosures | 9 Months Ended |
Sep. 30, 2018 | |
Segment Reporting [Abstract] | |
Segment Disclosures [Text Block] | Note 14 – Segment Disclosures Our reportable segments are Northeast G&P, Atlantic-Gulf, and West. All remaining business activities are included in Other. (See Note 1 – General, Description of Business, and Basis of Presentation .) Performance Measurement We evaluate segment operating performance based upon Modified EBITDA . This measure represents the basis of our internal financial reporting and is the primary performance measure used by our chief operating decision maker in measuring performance and allocating resources among our reportable segments. Intersegment revenues primarily represent the sale of NGLs from our natural gas processing plants to our marketing business. We define Modified EBITDA as follows: • Net income (loss) before: ◦ Income (loss) from discontinued operations; ◦ Provision (benefit) for income taxes; ◦ Interest incurred, net of interest capitalized; ◦ Equity earnings (losses); ◦ Gain on remeasurement of equity-method investment; ◦ Impairment of equity-method investments; ◦ Other investing income (loss) – net; ◦ Impairment of goodwill; ◦ Depreciation and amortization expenses; ◦ Accretion expense associated with asset retirement obligations for nonregulated operations. • This measure is further adjusted to include our proportionate share (based on ownership interest) of Modified EBITDA from our equity-method investments calculated consistently with the definition described above. The following table reflects the reconciliation of Segment revenues to Total revenues as reported in the Consolidated Statement of Income and Total assets by reportable segment. Northeast G&P Atlantic-Gulf West Other (1) Eliminations (2) Total (Millions) Three Months Ended September 30, 2018 Segment revenues: Service revenues External $ 236 $ 595 $ 533 $ 7 $ — $ 1,371 Internal 11 12 — 3 (26 ) — Total service revenues 247 607 533 10 (26 ) 1,371 Total service revenues – commodity consideration (external only) 6 18 97 — — 121 Product sales External 59 46 706 — — 811 Internal 10 85 26 — (121 ) — Total product sales 69 131 732 — (121 ) 811 Total revenues $ 322 $ 756 $ 1,362 $ 10 $ (147 ) $ 2,303 Three Months Ended September 30, 2017 Segment revenues: Service revenues External $ 207 $ 553 $ 544 $ 6 $ — $ 1,310 Internal 7 11 — 3 (21 ) — Total service revenues 214 564 544 9 (21 ) 1,310 Product sales External 56 57 459 9 — 581 Internal 5 49 26 — (80 ) — Total product sales 61 106 485 9 (80 ) 581 Total revenues $ 275 $ 670 $ 1,029 $ 18 $ (101 ) $ 1,891 Nine Months Ended September 30, 2018 Segment revenues: Service revenues External $ 677 $ 1,769 $ 1,599 $ 17 $ — $ 4,062 Internal 30 37 — 9 (76 ) — Total service revenues 707 1,806 1,599 26 (76 ) 4,062 Total service revenues – commodity consideration (external only) 14 45 257 — — 316 Product sales External 214 131 1,759 — — 2,104 Internal 28 198 63 — (289 ) — Total product sales 242 329 1,822 — (289 ) 2,104 Total revenues $ 963 $ 2,180 $ 3,678 $ 26 $ (365 ) $ 6,482 Northeast G&P Atlantic-Gulf West Other (1) Eliminations (2) Total (Millions) Nine Months Ended September 30, 2017 Segment revenues: Service revenues External $ 621 $ 1,620 $ 1,589 $ 23 $ — $ 3,853 Internal 27 27 — 9 (63 ) — Total service revenues 648 1,647 1,589 32 (63 ) 3,853 Product sales External 159 201 1,233 357 — 1,950 Internal 22 164 143 8 (337 ) — Total product sales 181 365 1,376 365 (337 ) 1,950 Total revenues $ 829 $ 2,012 $ 2,965 $ 397 $ (400 ) $ 5,803 September 30, 2018 Total assets $ 14,482 $ 16,361 $ 16,169 $ 748 $ (607 ) $ 47,153 December 31, 2017 Total assets $ 14,397 $ 14,989 $ 16,143 $ 1,449 $ (626 ) $ 46,352 ___________ (1) Decrease in Other Total assets due primarily to decreased cash balance. (2) Total assets Eliminations primarily relate to the intercompany notes and accounts receivable generated by our cash management program. The following table reflects the reconciliation of Modified EBITDA to Net income (loss) as reported in the Consolidated Statement of Income . Three Months Ended Nine Months Ended 2018 2017 2018 2017 (Millions) Modified EBITDA by segment: Northeast $ 281 $ 115 $ 786 $ 588 Atlantic-Gulf 492 430 1,418 1,334 West 412 (615 ) 1,214 126 Other 6 1,009 (49 ) 1,100 1,191 939 3,369 3,148 Accretion expense associated with asset retirement obligations for nonregulated operations (8 ) (7 ) (26 ) (23 ) Depreciation and amortization expenses (425 ) (433 ) (1,290 ) (1,308 ) Equity earnings (losses) 105 115 279 347 Other investing income (loss) – net 2 4 74 278 Proportional Modified EBITDA of equity-method investments (205 ) (202 ) (552 ) (611 ) Interest expense (270 ) (267 ) (818 ) (818 ) (Provision) benefit for income taxes (190 ) (24 ) (297 ) (126 ) Net income (loss) $ 200 $ 125 $ 739 $ 887 |
Revenue Recognition (Tables)
Revenue Recognition (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Revenue Recognition [Abstract] | |
Disaggregation of Revenue [Table Text Block] | The following table presents our revenue disaggregated by major service line: Northeast Midstream Atlantic- Gulf Midstream West Midstream Transco Northwest Pipeline Other Intercompany Eliminations Total (Millions) Three Months Ended September 30, 2018 Revenues from contracts with customers: Service revenues: Non-regulated gathering, processing, transportation, and storage: Monetary consideration $ 219 $ 139 $ 409 $ — $ — $ 1 $ (19 ) $ 749 Commodity consideration 5 19 97 — — — — 121 Regulated interstate natural gas transportation and storage — — — 457 110 — (1 ) 566 Other 23 4 11 — — — (4 ) 34 Total service revenues 247 162 517 457 110 1 (24 ) 1,470 Product Sales: NGL and natural gas 69 88 720 41 — — (117 ) 801 Other — — 12 — — — (3 ) 9 Total product sales 69 88 732 41 — — (120 ) 810 Total revenues from contracts with customers 316 250 1,249 498 110 1 (144 ) 2,280 Other revenues (1) 6 5 3 3 — 9 (3 ) 23 Total revenues $ 322 $ 255 $ 1,252 $ 501 $ 110 $ 10 $ (147 ) $ 2,303 Nine Months Ended September 30, 2018 Revenues from contracts with customers: Service revenues: Non-regulated gathering, processing, transportation, and storage: Monetary consideration $ 626 $ 404 $ 1,231 $ — $ — $ 2 $ (55 ) $ 2,208 Commodity consideration 14 45 257 — — — — 316 Regulated interstate natural gas transportation and storage — — — 1,368 330 — (2 ) 1,696 Other 65 12 35 1 — — (10 ) 103 Total service revenues 705 461 1,523 1,369 330 2 (67 ) 4,323 Product Sales: NGL and natural gas 242 232 1,799 96 — — (285 ) 2,084 Other — — 20 — — — (4 ) 16 Total product sales 242 232 1,819 96 — — (289 ) 2,100 Total revenues from contracts with customers 947 693 3,342 1,465 330 2 (356 ) 6,423 Other revenues (1) 16 14 6 8 — 24 (9 ) 59 Total revenues $ 963 $ 707 $ 3,348 $ 1,473 $ 330 $ 26 $ (365 ) $ 6,482 ______________________________ (1) Service revenues in our Consolidated Statement of Income include leasing revenues associated with our headquarters building and management fees that we receive for certain services we provide to operated joint ventures and other investments. The leasing revenues and the management fees do not constitute revenue from contracts with customers. Product sales in our Consolidated Statement of Income include amounts associated with our derivative contracts that are not within the scope of ASC 606. |
Contract with Customer, Asset and Liability [Table Text Block] | The following table presents a reconciliation of our contract assets: Quarter-to-Date September 30, 2018 Year-to-Date September 30, 2018 (Millions) Balance at beginning of period $ 39 $ 4 Revenue recognized in excess of cash received 17 53 Minimum volume commitments invoiced — (1 ) Balance at end of period $ 56 $ 56 |
Contract with Customer, Liability [Table Text Block] | The following table presents a reconciliation of our contract liabilities: Quarter-to-Date September 30, 2018 Year-to-Date September 30, 2018 (Millions) Balance at beginning of period $ 1,535 $ 1,596 Payments received and deferred 62 280 Deconsolidation of Jackalope interest (Note 3) — (52 ) Recognized in revenue (112 ) (339 ) Balance at end of period $ 1,485 $ 1,485 |
Contract with Customer, Liablity Expected Timing of Revenue Recognition [Table Text Block] | The following table presents the amount of the contract liabilities balance as of September 30, 2018 , expected to be recognized as revenue in each of the next five years as performance obligations are expected to be satisfied: (Millions) 2018 (remainder) $ 191 2019 257 2020 129 2021 110 2022 103 2023 100 Thereafter 595 Total $ 1,485 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block] | The following table presents the transaction price allocated to the remaining performance obligations under certain contracts as of September 30, 2018 . These primarily include long-term contracts containing MVCs associated with our midstream businesses, fixed payments associated with offshore production handling, and reservation charges on contracted capacity on our gas pipeline firm transportation contracts with customers, as well as storage capacity contracts. Amounts included in the table below for our interstate natural gas pipeline businesses reflect the rates for such services in our current FERC tariffs for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes is not currently known. As a practical expedient permitted by ASC 606, this table excludes variable consideration as well as consideration in contracts that is recognized in revenue as billed. It also excludes consideration received prior to September 30, 2018 , that will be recognized in future periods (see above for Contract Liabilities and the expected recognition of those amounts within revenue). As noted above, certain of our contracts contain evergreen and other renewal provisions for periods beyond the initial term of the contract. The remaining performance obligation amounts as of September 30, 2018 , do not consider potential future performance obligations for which the renewal has not been exercised. The table below also does not include contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service. (Millions) 2018 (remainder) $ 624 2019 2,465 2020 2,274 2021 2,106 2022 1,830 2023 1,650 Thereafter 12,471 Total $ 23,420 |
Contract With Customer Accounts Receivable [Table Text Block] | The following is a summary of our Trade accounts and other receivables as it relates to contracts with customers: September 30, 2018 January 1, 2018 (Millions) Accounts receivable related to revenues from contracts with customers $ 795 $ 958 Other accounts receivable 88 18 Total reflected in Trade accounts and other receivables $ 883 $ 976 |
Revenue Recognition Modified Retrospective Adoption Impact [Table Text Block] | The following table depicts the impact of the adoption of ASC 606 on our 2018 financial statements. The adjustment to Intangible assets – net of accumulated amortization in the table below relates to the recognition under ASC 606 of contract assets for MVC-related contracts associated with a 2014 acquisition. The recognition of these contract assets resulted in a lower purchase price allocation to intangible assets. The adoption of ASC 606 did not result in adjustments to total operating, investing, or financing cash flows. As Reported Adjustments resulting from adoption of ASC 606 Balance without adoption of ASC 606 (Millions) Consolidated Statement of Income Three Months Ended September 30, 2018 Service revenues $ 1,371 $ 5 $ 1,376 Service revenues – commodity consideration 121 (121 ) — Product sales 811 44 855 Total revenues 2,303 (72 ) 2,231 Product costs 790 (48 ) 742 Processing commodity expenses 30 (30 ) — Depreciation and amortization expenses 425 1 426 Total costs and expenses 1,802 (77 ) 1,725 Operating income (loss) 501 5 506 Interest incurred (286 ) 4 (282 ) Interest capitalized 16 (2 ) 14 Income (loss) before income taxes 390 7 397 Provision (benefit) for income taxes 190 1 191 Net income (loss) 200 6 206 Less: Net income (loss) attributable to noncontrolling interests 71 (1 ) 70 Net income (loss) attributable to The Williams Companies, Inc. 129 7 136 Basic earnings (loss) per common share $ 0.13 $ 0.01 $ 0.14 Diluted earnings (loss) per common share $ 0.13 $ 0.01 $ 0.14 Nine Months Ended September 30, 2018 Service revenues $ 4,062 $ 16 $ 4,078 Service revenues – commodity consideration 316 (316 ) — Product sales 2,104 86 2,190 Total revenues 6,482 (214 ) 6,268 Product costs 2,039 (143 ) 1,896 Processing commodity expenses 91 (91 ) — Operating and maintenance expenses 1,134 3 1,137 Depreciation and amortization expenses 1,290 2 1,292 Total costs and expenses 5,080 (229 ) 4,851 As Reported Adjustments resulting from adoption of ASC 606 Balance without adoption of ASC 606 (Millions) Operating income (loss) $ 1,402 $ 15 $ 1,417 Equity earnings (losses) 279 1 280 Other investing income (loss) - net 74 (9 ) 65 Interest incurred (856 ) 11 (845 ) Interest capitalized 38 (6 ) 32 Income (loss) before income taxes 1,036 12 1,048 Provision (benefit) for income taxes 297 1 298 Net income (loss) 739 11 750 Net income (loss) attributable to The Williams Companies, Inc. 416 11 427 Basic earnings (loss) per common share $ 0.47 $ 0.01 $ 0.48 Diluted earnings (loss) per common share $ 0.46 $ 0.01 $ 0.47 Consolidated Statement of Comprehensive Income Three Months Ended September 30, 2018 Net income (loss) $ 200 $ 6 $ 206 Comprehensive income (loss) 206 6 212 Less: Comprehensive income (loss) attributable to noncontrolling interests 72 (1 ) 71 Comprehensive income (loss) attributable to The Williams Companies, Inc. 134 7 141 Nine Months Ended September 30, 2018 Net income (loss) $ 739 $ 11 $ 750 Comprehensive income (loss) 748 11 759 Comprehensive income (loss) attributable to The Williams Companies, Inc. 427 11 438 Consolidated Balance Sheet September 30, 2018 Inventories $ 153 $ (8 ) $ 145 Other current assets and deferred charges 242 (53 ) 189 Total current assets 1,984 (61 ) 1,923 Investments 7,427 (1 ) 7,426 Property, plant, and equipment 39,953 (6 ) 39,947 Property, plant, and equipment – net 28,674 (6 ) 28,668 Intangible assets – net of accumulated amortization 8,324 63 8,387 Regulatory assets, deferred charges, and other 744 (4 ) 740 Total assets 47,153 (9 ) 47,144 Deferred income tax liabilities 1,648 27 1,675 Regulatory liabilities, deferred income, and other 4,376 (159 ) 4,217 Retained deficit (9,018 ) 95 (8,923 ) Total stockholders’ equity 15,610 95 15,705 Noncontrolling interests in consolidated subsidiaries $ 1,349 $ 28 $ 1,377 Total equity 16,959 123 17,082 Total liabilities and equity 47,153 (9 ) 47,144 As Reported Adjustments resulting from adoption of ASC 606 Balance without adoption of ASC 606 (Millions) Consolidated Statement of Changes in Equity September 30, 2018 Adoption of ASC 606 $ (121 ) $ 121 $ — Net income (loss) 739 11 750 Deconsolidation of subsidiary (267 ) (9 ) (276 ) Net increase (decrease) in equity 784 123 907 Balance at September 30, 2018 16,959 123 17,082 |
Variable Interest Entities (Tab
Variable Interest Entities (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Variable Interest Entity Disclosures [Abstract] | |
Schedule of Variable Interest Entities [Table Text Block] | The following table presents amounts included in our Consolidated Balance Sheet that are for the use or obligation of our consolidated VIEs: September 30, December 31, 2017 (1) Classification (Millions) Assets (liabilities): Cash and cash equivalents $ 32 $ 881 Cash and cash equivalents Trade accounts and other receivables – net 57 972 Trade accounts and other receivables Inventories — 113 Inventories Other current assets 1 176 Other current assets and deferred charges Investments — 6,552 Investments Property, plant, and equipment – net 2,398 27,912 Property, plant, and equipment – net Intangible assets – net 1,189 8,790 Intangible assets – net of accumulated amortization Regulatory assets, deferred charges, and other noncurrent assets — 507 Regulatory assets, deferred charges, and other Accounts payable (16 ) (957 ) Accounts payable Accrued liabilities including current asset retirement obligations (98 ) (857 ) Accrued liabilities Long-term debt due within one year — (501 ) Long-term debt due within one year Long-term debt — (15,996 ) Long-term debt Deferred income tax liabilities — (16 ) Deferred income tax liabilities Noncurrent asset retirement obligations (104 ) (944 ) Regulatory liabilities, deferred income, and other Regulatory liabilities, deferred income, and other noncurrent liabilities (189 ) (2,809 ) Regulatory liabilities, deferred income, and other _________________ (1) Includes WPZ, which was a consolidated VIE at December 31, 2017 (see Note 1 – General, Description of Business, and Basis of Presentation ). |
Divestitures and Assets Held _2
Divestitures and Assets Held for Sale (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
Disclosure of Long Lived Assets Held-for-sale [Table Text Block] | The following table presents the carrying amounts of the major classes of the Four Corners area assets and liabilities, which are presented within Assets held for sale and Liabilities held for sale in the Consolidated Balance Sheet: Carrying Amount September 30, 2018 (Millions) Assets: Current assets $ 23 Property, plant, and equipment – net 539 Other noncurrent assets 12 $ 574 Liabilities: Current liabilities $ 22 Other noncurrent liabilities 23 $ 45 |
Four Corners [Member] | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
Results of Operations of Disposal Group [Table Text Block] | The following table presents the results of operations for the Four Corners area: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (Millions) Income (loss) before income taxes of Four Corners area $ 25 $ 14 $ 52 $ 31 Income (loss) before income taxes of Four Corners area attributable to The Williams Companies, Inc. 23 10 43 23 |
Williams Olefins, L.L.C. [Member] | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
Results of Operations of Disposal Group [Table Text Block] | The following table presents the results of operations for the Geismar Interest, excluding the gain noted above: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (Millions) Income (loss) before income taxes of the Geismar Interest $ — $ 1 $ — $ 26 Income (loss) before income taxes of the Geismar Interest attributable to The Williams Companies, Inc. — 1 — 19 |
Other Income and Expenses (Tabl
Other Income and Expenses (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Other Income and Expenses [Abstract] | |
Other Income and Expenses [Table Text Block] | The following table presents certain gains or losses reflected in Other (income) expense – net within Costs and expenses in our Consolidated Statement of Income : Three Months Ended Nine Months Ended 2018 2017 2018 2017 (Millions) Atlantic-Gulf Amortization of regulatory assets associated with asset retirement obligations $ 8 $ 8 $ 24 $ 25 Accrual of regulatory liability related to overcollection of certain employee expenses 5 5 16 16 Project development costs related to Constitution (see Note 3) 1 4 4 12 Adjustments to regulatory liability related to Tax Reform — — (10 ) — Gain on asset retirement (10 ) (5 ) (10 ) (5 ) West Gains on contract settlements and terminations — — — (15 ) Adjustments to regulatory liability related to Tax Reform — — (7 ) — Regulatory charge per approved rates related to Tax Reform 6 — 18 — Charge for regulatory liability associated with the decrease in Northwest Pipeline’s estimated deferred state income tax rates following WPZ Merger 12 — 12 — Other Benefit of regulatory asset associated with increase in Transco’s estimated deferred state income tax rate following WPZ Merger (37 ) — (37 ) — Gain on sale of Refinery Grade Propylene Splitter — — — (12 ) |
Provision (Benefit) for Incom_2
Provision (Benefit) for Income Taxes (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block] | The Provision (benefit) for income taxes includes: Three Months Ended Nine Months Ended 2018 2017 2018 2017 (Millions) Current: Federal $ (19 ) $ 7 $ (55 ) $ 10 State — 9 1 17 (19 ) 16 (54 ) 27 Deferred: Federal 188 (11 ) 312 63 State 21 19 39 36 209 8 351 99 Provision (benefit) for income taxes $ 190 $ 24 $ 297 $ 126 |
Earnings Per Common Share (Tabl
Earnings Per Common Share (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Earnings Per Share [Abstract] | |
Earnings per common share [Table Text Block] | Three Months Ended Nine Months Ended 2018 2017 2018 2017 (Dollars in millions, except per-share amounts; shares in thousands) Net income available to common stockholders $ 129 $ 33 $ 416 $ 487 Basic weighted-average shares 1,023,587 826,779 893,706 825,925 Effect of dilutive securities: Nonvested restricted stock units 2,387 1,889 2,102 1,567 Stock options 530 700 514 658 Diluted weighted-average shares 1,026,504 829,368 896,322 828,150 Earnings per common share: Basic $ .13 $ .04 $ .47 $ .59 Diluted $ .13 $ .04 $ .46 $ .59 |
Employee Benefit Plans (Tables)
Employee Benefit Plans (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Retirement Benefits [Abstract] | |
Schedule of Net Benefit Costs [Table Text Block] | Net periodic benefit cost (credit) is as follows: Pension Benefits Three Months Ended Nine Months Ended 2018 2017 2018 2017 (Millions) Components of net periodic benefit cost (credit): Service cost $ 12 $ 13 $ 37 $ 38 Interest cost 12 15 35 44 Expected return on plan assets (16 ) (21 ) (47 ) (62 ) Amortization of net actuarial loss 6 6 17 20 Net actuarial loss from settlements 1 — 2 — Net periodic benefit cost (credit) $ 15 $ 13 $ 44 $ 40 Other Postretirement Benefits Three Months Ended Nine Months Ended 2018 2017 2018 2017 (Millions) Components of net periodic benefit cost (credit): Service cost $ 1 $ — $ 1 $ 1 Interest cost 1 2 5 6 Expected return on plan assets (2 ) (3 ) (8 ) (9 ) Amortization of prior service credit — (3 ) (1 ) (10 ) Reclassification to regulatory liability — 1 1 3 Net periodic benefit cost (credit) $ — $ (3 ) $ (2 ) $ (9 ) |
Debt and Banking Arrangements (
Debt and Banking Arrangements (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Debt Disclosure [Abstract] | |
Schedule of Line of Credit Facilities [Table Text Block] | Credit Facilities September 30, 2018 Stated Capacity Outstanding (Millions) Long-term credit facility (1) $ 4,500 $ — Letters of credit under certain bilateral bank agreements 14 (1) In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. |
Stockholders' Equity (Tables)
Stockholders' Equity (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Stockholders' Equity Note [Abstract] | |
Accumulated Other Comprehensive Income (Loss) [Table Text Block] | AOCI The following table presents the changes in Accumulated other comprehensive income (loss) (AOCI) by component, net of income taxes: Cash Flow Hedges Foreign Currency Translation Pension and Other Postretirement Benefits Total (Millions) Balance at December 31, 2017 $ (2 ) $ (1 ) $ (235 ) $ (238 ) Adoption of ASU 2018-02 (Note 1) — — (61 ) (61 ) WPZ Merger (Note 1) (3 ) — — (3 ) Other comprehensive income (loss): Other comprehensive income (loss) before reclassifications (14 ) — 4 (10 ) Amounts reclassified from accumulated other comprehensive income (loss) 7 — 14 21 Other comprehensive income (loss) (7 ) — 18 11 Balance at September 30, 2018 $ (12 ) $ (1 ) $ (278 ) $ (291 ) |
Reclassifications Out Of Accumulated Other Comprehensive Income [Table Text Block] | Reclassifications out of AOCI are presented in the following table by component for the nine months ended September 30, 2018 : Component Reclassifications Classification (Millions) Cash flow hedges: Energy commodity contracts $ 13 Product sales Pension and other postretirement benefits: Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit) 19 Note 9 – Employee Benefit Plans Total before tax 32 Income tax benefit (8 ) Provision (benefit) for income taxes Net of income tax 24 Noncontrolling interest (3 ) Net income (loss) attributable to noncontrolling interests Reclassifications during the period $ 21 |
Fair Value Measurements and G_2
Fair Value Measurements and Guarantees (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Assets and Liabilities Measured On Recurring Basis [Table Text Block] | The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, commercial paper, and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table. Fair Value Measurements Using Carrying Amount Fair Value Quoted Prices In Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (Millions) Assets (liabilities) at September 30, 2018: Measured on a recurring basis: ARO Trust investments $ 157 $ 157 $ 157 $ — $ — Energy derivatives assets not designated as hedging instruments 6 6 6 — — Energy derivatives liabilities designated as hedging instruments (14 ) (14 ) (13 ) (1 ) — Energy derivatives liabilities not designated as hedging instruments (9 ) (9 ) (6 ) — (3 ) Additional disclosures: Other receivables 21 21 21 — — Long-term debt, including current portion (21,442 ) (22,532 ) — (22,532 ) — Guarantees (43 ) (30 ) — (14 ) (16 ) Assets (liabilities) at December 31, 2017: Measured on a recurring basis: ARO Trust investments $ 135 $ 135 $ 135 $ — $ — Energy derivatives liabilities designated as hedging instruments (3 ) (3 ) (2 ) (1 ) — Energy derivatives liabilities not designated as hedging instruments (3 ) (3 ) — — (3 ) Additional disclosures: Other receivables 7 7 7 — — Long-term debt, including current portion (20,935 ) (23,005 ) — (23,005 ) — Guarantees (43 ) (30 ) — (14 ) (16 ) |
Fair Value Measurements, Nonrecurring [Table Text Block] | The following table presents impairments of assets associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy, except as specifically noted. Impairments Nine Months Ended September 30, Classification Segment Date of Measurement Fair Value 2018 2017 (Millions) Certain idle pipeline assets (1) Property, plant, and equipment – net Other June 30, 2018 $ 25 $ 66 Certain gathering operations (2) Property, plant, and equipment – net and Intangible assets - net of accumulated amortization West September 30, 2017 439 $ 1,019 Certain gathering operations (3) Property, plant, and equipment – net and Intangible assets - net of accumulated amortization Northeast G&P September 30, 2017 21 115 Certain NGL pipeline (4) Property, plant, and equipment – net Other September 30, 2017 32 68 Certain olefins pipeline project (5) Property, plant, and equipment – net Other June 30, 2017 18 23 Fair value measurements of certain assets 66 1,225 Other impairments and write-downs (6) — 11 Impairment of certain assets $ 66 $ 1,236 _______________ (1) Relates to certain idle pipelines. The estimated fair value was determined by a market approach incorporating information derived from bids received for these assets, which are currently being marketed for sale together with certain other assets. These inputs result in a fair value measurement within Level 2 of the fair value hierarchy. (2) Relates to certain gathering operations in the Mid-Continent region. During the third quarter of 2017, we received solicitations and engaged in negotiations for the sale of certain of these assets which led to our impairment evaluation. The estimated fair value was determined using an income approach and incorporated market inputs based on ongoing negotiations for a potential sale of a portion of the underlying assets. For the income approach, we utilized a discount rate of 10.2 percent , reflecting an estimated cost of capital and risks associated with the underlying assets. (3) Relates to certain gathering operations in the Marcellus South region resulting from an anticipated decline in future volumes following a third-quarter 2017 shut-in by the primary producer. The estimated fair value was determined by the income approach utilizing a discount rate of 11.1 percent , reflecting an estimated cost of capital and risks associated with the underlying assets. (4) Relates to an NGL pipeline near the Houston Ship Channel region which we anticipate will be underutilized for the foreseeable future. The estimated fair value was primarily determined by using a market approach based on our analysis of observable inputs in the principal market. (5) Relates primarily to project development costs associated with an olefins pipeline project in the Gulf Coast region, the likelihood of completion of which is now considered remote. The estimated fair value of the remaining pipe and equipment considered a market approach based on our analysis of observable inputs in the principal market, as well as an estimate of replacement cost. (6) Reflects multiple individually insignificant impairments and write-downs of other certain assets that may no longer be in use or are surplus in nature for which the fair value was determined to be lower than the carrying value. |
Segment Disclosures (Tables)
Segment Disclosures (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Segment Reporting [Abstract] | |
Reconciliation of Revenue from Segments to Consolidated [Table Text Block] | The following table reflects the reconciliation of Segment revenues to Total revenues as reported in the Consolidated Statement of Income and Total assets by reportable segment. Northeast G&P Atlantic-Gulf West Other (1) Eliminations (2) Total (Millions) Three Months Ended September 30, 2018 Segment revenues: Service revenues External $ 236 $ 595 $ 533 $ 7 $ — $ 1,371 Internal 11 12 — 3 (26 ) — Total service revenues 247 607 533 10 (26 ) 1,371 Total service revenues – commodity consideration (external only) 6 18 97 — — 121 Product sales External 59 46 706 — — 811 Internal 10 85 26 — (121 ) — Total product sales 69 131 732 — (121 ) 811 Total revenues $ 322 $ 756 $ 1,362 $ 10 $ (147 ) $ 2,303 Three Months Ended September 30, 2017 Segment revenues: Service revenues External $ 207 $ 553 $ 544 $ 6 $ — $ 1,310 Internal 7 11 — 3 (21 ) — Total service revenues 214 564 544 9 (21 ) 1,310 Product sales External 56 57 459 9 — 581 Internal 5 49 26 — (80 ) — Total product sales 61 106 485 9 (80 ) 581 Total revenues $ 275 $ 670 $ 1,029 $ 18 $ (101 ) $ 1,891 Nine Months Ended September 30, 2018 Segment revenues: Service revenues External $ 677 $ 1,769 $ 1,599 $ 17 $ — $ 4,062 Internal 30 37 — 9 (76 ) — Total service revenues 707 1,806 1,599 26 (76 ) 4,062 Total service revenues – commodity consideration (external only) 14 45 257 — — 316 Product sales External 214 131 1,759 — — 2,104 Internal 28 198 63 — (289 ) — Total product sales 242 329 1,822 — (289 ) 2,104 Total revenues $ 963 $ 2,180 $ 3,678 $ 26 $ (365 ) $ 6,482 Northeast G&P Atlantic-Gulf West Other (1) Eliminations (2) Total (Millions) Nine Months Ended September 30, 2017 Segment revenues: Service revenues External $ 621 $ 1,620 $ 1,589 $ 23 $ — $ 3,853 Internal 27 27 — 9 (63 ) — Total service revenues 648 1,647 1,589 32 (63 ) 3,853 Product sales External 159 201 1,233 357 — 1,950 Internal 22 164 143 8 (337 ) — Total product sales 181 365 1,376 365 (337 ) 1,950 Total revenues $ 829 $ 2,012 $ 2,965 $ 397 $ (400 ) $ 5,803 September 30, 2018 Total assets $ 14,482 $ 16,361 $ 16,169 $ 748 $ (607 ) $ 47,153 December 31, 2017 Total assets $ 14,397 $ 14,989 $ 16,143 $ 1,449 $ (626 ) $ 46,352 ___________ (1) Decrease in Other Total assets due primarily to decreased cash balance. (2) Total assets Eliminations primarily relate to the intercompany notes and accounts receivable generated by our cash management program. |
Reconciliation of Modified EBITDA to Net Income (Loss) [Table Text Block] | The following table reflects the reconciliation of Modified EBITDA to Net income (loss) as reported in the Consolidated Statement of Income . Three Months Ended Nine Months Ended 2018 2017 2018 2017 (Millions) Modified EBITDA by segment: Northeast $ 281 $ 115 $ 786 $ 588 Atlantic-Gulf 492 430 1,418 1,334 West 412 (615 ) 1,214 126 Other 6 1,009 (49 ) 1,100 1,191 939 3,369 3,148 Accretion expense associated with asset retirement obligations for nonregulated operations (8 ) (7 ) (26 ) (23 ) Depreciation and amortization expenses (425 ) (433 ) (1,290 ) (1,308 ) Equity earnings (losses) 105 115 279 347 Other investing income (loss) – net 2 4 74 278 Proportional Modified EBITDA of equity-method investments (205 ) (202 ) (552 ) (611 ) Interest expense (270 ) (267 ) (818 ) (818 ) (Provision) benefit for income taxes (190 ) (24 ) (297 ) (126 ) Net income (loss) $ 200 $ 125 $ 739 $ 887 |
General, Description of Busin_2
General, Description of Business, and Basis of Presentation (Details) - USD ($) $ / shares in Units, $ in Millions | Aug. 10, 2018 | Jan. 09, 2017 | Feb. 03, 2017 | Jan. 31, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Jun. 30, 2018 | Sep. 30, 2018 | Sep. 30, 2017 | Jul. 30, 2018 | Jan. 01, 2018 | Dec. 31, 2017 | Mar. 31, 2017 |
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | |||||||||||||
Operating Costs and Expenses | $ 389 | $ 403 | $ 1,134 | $ 1,166 | |||||||||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Net | (4) | ||||||||||||
Other Nonoperating Income (Expense) | 52 | 23 | 99 | 124 | |||||||||
Operating Income (Loss) | (501) | (274) | (1,402) | (1,082) | |||||||||
Net Cash Provided by (Used in) Operating Activities | 2,331 | 2,231 | |||||||||||
Net Cash Provided by (Used in) Investing Activities | 2,983 | (662) | |||||||||||
Stock Issued During Period, Value, New Issues | 35 | ||||||||||||
Additional Paid in Capital, Common Stock | 24,680 | 24,680 | $ 18,508 | ||||||||||
Other Assets, Noncurrent | 744 | 744 | 619 | ||||||||||
Accumulated Other Comprehensive Income (Loss), Net of Tax | 291 | 291 | 238 | ||||||||||
Stockholders' Equity Attributable to Noncontrolling Interest | (1,349) | (1,349) | (6,519) | ||||||||||
Deferred Tax Liabilities, Net, Noncurrent | $ (1,648) | (1,648) | $ (3,147) | ||||||||||
Noncontrolling Interest [Member] | |||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | |||||||||||||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Net | (18) | ||||||||||||
Stock Issued During Period, Value, New Issues | 0 | ||||||||||||
Capital in excess of par value [Member] | |||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | |||||||||||||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Net | 14 | ||||||||||||
Stock Issued During Period, Value, New Issues | $ 0 | ||||||||||||
Financial Repositioning [Member] | |||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | |||||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 277,000 | 59,000,000 | 289,000,000 | ||||||||||
Payments to Acquire Limited Partnership Interests | $ 10 | 56 | |||||||||||
Sale of Stock, Price Per Share | $ 36.08586 | ||||||||||||
Financial Repositioning [Member] | Williams Partners L.P. [Member] | |||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | |||||||||||||
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest | 2.00% | ||||||||||||
Dividend Reinvestment Program [Member] | |||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | |||||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 1,230,657 | ||||||||||||
Sale of Stock, Consideration Received on Transaction | $ 46 | ||||||||||||
Accounting Standards Update 2017-07 [Member] | |||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | |||||||||||||
Operating Costs and Expenses | 3 | 9 | |||||||||||
Other Nonoperating Income (Expense) | 3 | 9 | |||||||||||
Operating Income (Loss) | $ 3 | 9 | |||||||||||
Accounting Standards Update 2016-15 [Member] | |||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | |||||||||||||
Net Cash Provided by (Used in) Operating Activities | 394 | ||||||||||||
Net Cash Provided by (Used in) Investing Activities | $ 394 | ||||||||||||
Accounting Standards Update 2014-09 [Member] | |||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | |||||||||||||
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets | $ 121 | ||||||||||||
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accounting Standards Update 2018-02 [Member] | |||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | |||||||||||||
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets | 61 | ||||||||||||
Retained Deficit | Accounting Standards Update 2018-02 [Member] | |||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | |||||||||||||
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets | $ (61) | ||||||||||||
WPZ Merger Agreement [Member] | |||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | |||||||||||||
Limited Partners' Capital Account, Units Outstanding | 256,000,000 | ||||||||||||
Stock Issued During Period, Shares, New Issues | 382,000,000 | ||||||||||||
Stock Issued During Period, Value, New Issues | $ 382 | ||||||||||||
Additional Paid in Capital, Common Stock | 6,112 | ||||||||||||
Other Assets, Noncurrent | 33 | ||||||||||||
Accumulated Other Comprehensive Income (Loss), Net of Tax | 3 | ||||||||||||
Stockholders' Equity Attributable to Noncontrolling Interest | 4,629 | ||||||||||||
Deferred Tax Liabilities, Net, Noncurrent | $ 1,829 | ||||||||||||
Northeast G And P [Member] | Cardinal Gas Services LLC [Member] | |||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | |||||||||||||
Variable Interest Entity Ownership Percentage | 66.00% | ||||||||||||
Northeast G And P [Member] | Appalachia Midstream Services, LLC [Member] | |||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | |||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 66.00% | ||||||||||||
Atlantic Gulf [Member] | Constitution Pipeline Company LLC [Member] | |||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | |||||||||||||
Variable Interest Entity Ownership Percentage | 41.00% | ||||||||||||
Atlantic Gulf [Member] | Gulfstar One [Member] | |||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | |||||||||||||
Variable Interest Entity Ownership Percentage | 51.00% | ||||||||||||
Conway Fractionator [Member] | West [Member] | |||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | |||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 50.00% | ||||||||||||
Geismar [Member] | Other [Member] | |||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | |||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 88.50% | ||||||||||||
Gulfstream Natural Gas System, L.L.C.[Member] | Atlantic Gulf [Member] | |||||||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||||||
Equity Method Investment, Ownership Percentage | 50.00% | 50.00% | |||||||||||
Utica East Ohio Midstream, LLC [Member] | Northeast G And P [Member] | |||||||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||||||
Equity Method Investment, Ownership Percentage | 62.00% | 62.00% | |||||||||||
Delaware Basin Gas Gathering System [Member] | West [Member] | |||||||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||||||
Equity Method Investment, Ownership Percentage | 50.00% | ||||||||||||
Laurel Mountain Midstream, LLC [Member] | Northeast G And P [Member] | |||||||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||||||
Equity Method Investment, Ownership Percentage | 69.00% | 69.00% | |||||||||||
Caiman Energy II [Member] | Northeast G And P [Member] | |||||||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||||||
Equity Method Investment, Ownership Percentage | 58.00% | 58.00% | |||||||||||
Discovery Producer Services LLC [Member] | Atlantic Gulf [Member] | |||||||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||||||
Equity Method Investment, Ownership Percentage | 60.00% | 60.00% | |||||||||||
Overland Pass Pipeline Company LLC [Member] | West [Member] | |||||||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||||||
Equity Method Investment, Ownership Percentage | 50.00% | 50.00% | |||||||||||
Jackalope Gas Gathering Services LLC [Member] | West [Member] | |||||||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||||||
Equity Method Investment, Ownership Percentage | 50.00% | 50.00% | |||||||||||
Rocky Mountain Midstream Holdings LLC [Member] | West [Member] | |||||||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||||||
Equity Method Investment, Ownership Percentage | 43.00% | 43.00% | 40.00% |
Revenue Recognition Revenue by
Revenue Recognition Revenue by Category (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | ||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 2,280 | $ 6,423 | |||
Total revenues | 2,303 | $ 1,891 | 6,482 | $ 5,803 | |
Northeast Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 316 | 947 | |||
Total revenues | 322 | 963 | |||
Atlantic Gulf Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 250 | 693 | |||
Total revenues | 255 | 707 | |||
West Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,249 | 3,342 | |||
Total revenues | 1,252 | 3,348 | |||
Transco [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 498 | 1,465 | |||
Total revenues | 501 | 1,473 | |||
Northwest Pipeline [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 110 | 330 | |||
Total revenues | 110 | 330 | |||
Other Geographical [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1 | 2 | |||
Total revenues | 10 | 26 | |||
Intercompany Eliminations [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | (144) | (356) | |||
Total revenues | (147) | (365) | |||
NonRegulated Service Monetary Consideration [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 749 | 2,208 | |||
NonRegulated Service Monetary Consideration [Member] | Northeast Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 219 | 626 | |||
NonRegulated Service Monetary Consideration [Member] | Atlantic Gulf Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 139 | 404 | |||
NonRegulated Service Monetary Consideration [Member] | West Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 409 | 1,231 | |||
NonRegulated Service Monetary Consideration [Member] | Transco [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||
NonRegulated Service Monetary Consideration [Member] | Northwest Pipeline [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||
NonRegulated Service Monetary Consideration [Member] | Other Geographical [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1 | 2 | |||
NonRegulated Service Monetary Consideration [Member] | Intercompany Eliminations [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | (19) | (55) | |||
NonRegulated Service Commodity Consideration [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 121 | 316 | |||
NonRegulated Service Commodity Consideration [Member] | Northeast Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 5 | 14 | |||
NonRegulated Service Commodity Consideration [Member] | Atlantic Gulf Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 19 | 45 | |||
NonRegulated Service Commodity Consideration [Member] | West Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 97 | 257 | |||
NonRegulated Service Commodity Consideration [Member] | Transco [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||
NonRegulated Service Commodity Consideration [Member] | Northwest Pipeline [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||
NonRegulated Service Commodity Consideration [Member] | Other Geographical [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||
NonRegulated Service Commodity Consideration [Member] | Intercompany Eliminations [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||
Regulated Service [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 566 | 1,696 | |||
Regulated Service [Member] | Northeast Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||
Regulated Service [Member] | Atlantic Gulf Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||
Regulated Service [Member] | West Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||
Regulated Service [Member] | Transco [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 457 | 1,368 | |||
Regulated Service [Member] | Northwest Pipeline [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 110 | 330 | |||
Regulated Service [Member] | Other Geographical [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||
Regulated Service [Member] | Intercompany Eliminations [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | (1) | (2) | |||
Other Service [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 34 | 103 | |||
Other Service [Member] | Northeast Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 23 | 65 | |||
Other Service [Member] | Atlantic Gulf Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 4 | 12 | |||
Other Service [Member] | West Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 11 | 35 | |||
Other Service [Member] | Transco [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 1 | |||
Other Service [Member] | Northwest Pipeline [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||
Other Service [Member] | Other Geographical [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||
Other Service [Member] | Intercompany Eliminations [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | (4) | (10) | |||
Total Service Revenues [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,470 | 4,323 | |||
Total Service Revenues [Member] | Northeast Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 247 | 705 | |||
Total Service Revenues [Member] | Atlantic Gulf Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 162 | 461 | |||
Total Service Revenues [Member] | West Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 517 | 1,523 | |||
Total Service Revenues [Member] | Transco [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 457 | 1,369 | |||
Total Service Revenues [Member] | Northwest Pipeline [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 110 | 330 | |||
Total Service Revenues [Member] | Other Geographical [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1 | 2 | |||
Total Service Revenues [Member] | Intercompany Eliminations [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | (24) | (67) | |||
NGL And Natural Gas Product Sales [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 801 | 2,084 | |||
NGL And Natural Gas Product Sales [Member] | Northeast Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 69 | 242 | |||
NGL And Natural Gas Product Sales [Member] | Atlantic Gulf Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 88 | 232 | |||
NGL And Natural Gas Product Sales [Member] | West Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 720 | 1,799 | |||
NGL And Natural Gas Product Sales [Member] | Transco [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 41 | 96 | |||
NGL And Natural Gas Product Sales [Member] | Northwest Pipeline [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||
NGL And Natural Gas Product Sales [Member] | Other Geographical [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||
NGL And Natural Gas Product Sales [Member] | Intercompany Eliminations [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | (117) | (285) | |||
Other Product Sales [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 9 | 16 | |||
Other Product Sales [Member] | Northeast Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||
Other Product Sales [Member] | Atlantic Gulf Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||
Other Product Sales [Member] | West Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 12 | 20 | |||
Other Product Sales [Member] | Transco [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||
Other Product Sales [Member] | Northwest Pipeline [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||
Other Product Sales [Member] | Other Geographical [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||
Other Product Sales [Member] | Intercompany Eliminations [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | (3) | (4) | |||
Total Product Sales [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 810 | 2,100 | |||
Total Product Sales [Member] | Northeast Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 69 | 242 | |||
Total Product Sales [Member] | Atlantic Gulf Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 88 | 232 | |||
Total Product Sales [Member] | West Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 732 | 1,819 | |||
Total Product Sales [Member] | Transco [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 41 | 96 | |||
Total Product Sales [Member] | Northwest Pipeline [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||
Total Product Sales [Member] | Other Geographical [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||
Total Product Sales [Member] | Intercompany Eliminations [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | (120) | (289) | |||
Product and Service, Other [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | [1] | 23 | 59 | ||
Product and Service, Other [Member] | Northeast Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 6 | 16 | |||
Product and Service, Other [Member] | Atlantic Gulf Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 5 | 14 | |||
Product and Service, Other [Member] | West Midstream [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 3 | 6 | |||
Product and Service, Other [Member] | Transco [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 3 | 8 | |||
Product and Service, Other [Member] | Northwest Pipeline [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | |||
Product and Service, Other [Member] | Other Geographical [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 9 | 24 | |||
Product and Service, Other [Member] | Intercompany Eliminations [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ (3) | $ (9) | |||
[1] | Service revenues in our Consolidated Statement of Income include leasing revenues associated with our headquarters building and management fees that we receive for certain services we provide to operated joint ventures and other investments. The leasing revenues and the management fees do not constitute revenue from contracts with customers. Product sales in our Consolidated Statement of Income include amounts associated with our derivative contracts that are not within the scope of ASC 606. |
Revenue Recognition Contract As
Revenue Recognition Contract Assets (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Dec. 31, 2017 | |
Revenue Recognition [Abstract] | ||||
Contract with Customer, Asset, Net | $ 56 | $ 56 | $ 39 | $ 4 |
Contract with Customer Asset Amounts Recognized In Excess Of Cash Received | 17 | 53 | ||
Contract With Customer Asset Minimum Volume Commitments Invoiced | $ 0 | $ (1) |
Revenue Recognition Contract Li
Revenue Recognition Contract Liabilities (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Dec. 31, 2017 | |
Revenue Recognition [Abstract] | ||||
Contract with Customer, Liability | $ 1,485 | $ 1,485 | $ 1,535 | $ 1,596 |
Contract with Customer, Liability, Cumulative Catch-up Adjustment to Revenue, Change in Estimate of Transaction Price | 62 | 280 | ||
Variable Interest Entity Nonconsolidated Contract Liability 1 | 0 | (52) | ||
Contract with Customer, Liability, Revenue Recognized | (112) | (339) | ||
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-10-01 | ||||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||||
Revenue, Remaining Performance Obligation, Amount | $ 191 | $ 191 | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 3 months | 3 months | ||
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | ||||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||||
Revenue, Remaining Performance Obligation, Amount | $ 257 | $ 257 | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year | 1 year | ||
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | ||||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||||
Revenue, Remaining Performance Obligation, Amount | $ 129 | $ 129 | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year | 1 year | ||
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | ||||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||||
Revenue, Remaining Performance Obligation, Amount | $ 110 | $ 110 | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year | 1 year | ||
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | ||||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||||
Revenue, Remaining Performance Obligation, Amount | $ 103 | $ 103 | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year | 1 year | ||
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | ||||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||||
Revenue, Remaining Performance Obligation, Amount | $ 100 | $ 100 | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year | 1 year | ||
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | ||||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||||
Revenue, Remaining Performance Obligation, Amount | $ 595 | $ 595 | ||
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | ||||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||||
Revenue, Remaining Performance Obligation, Amount | $ 1,485 | $ 1,485 |
Revenue Recognition Remaining P
Revenue Recognition Remaining Performance Obligations (Details) - Remaining Performance Obligations [Member] $ in Millions | Sep. 30, 2018USD ($) |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-10-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 420 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 3 months |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 2,465 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 2,274 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 2,106 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 1,830 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 1,650 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 12,471 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 23,420 |
Revenue Recognition Accounts Re
Revenue Recognition Accounts Receivable (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Receivables, Net, Current | $ 883 | $ 976 |
Accounts Receivable Related To Contracts With Customers [Member] | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Receivables, Net, Current | 795 | 958 |
Other Accounts Receivable [Member] | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Receivables, Net, Current | $ 88 | $ 18 |
Revenue Recognition Impact of A
Revenue Recognition Impact of Adoption of ASC 606 (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | |
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 2,280 | $ 6,423 | |||
Service revenues – commodity consideration | 121 | $ 0 | 316 | $ 0 | |
Total revenues | 2,303 | 1,891 | 6,482 | 5,803 | |
Processing commodity expenses | 30 | 0 | 91 | 0 | |
Operating Costs and Expenses | 389 | 403 | 1,134 | 1,166 | |
Depreciation and amortization expenses | 425 | 433 | 1,290 | 1,308 | |
Total costs and expenses | 1,802 | 1,617 | 5,080 | 4,721 | |
Operating Income (Loss) | 501 | 274 | 1,402 | 1,082 | |
Equity earnings (losses) | 105 | 115 | 279 | 347 | |
Other investing income (loss) - net | 2 | 4 | 74 | 278 | |
Interest incurred | (286) | (275) | (856) | (842) | |
Interest capitalized | 16 | 8 | 38 | 24 | |
Income (loss) before income taxes | 390 | 149 | 1,036 | 1,013 | |
Provision (benefit) for income taxes | 190 | 24 | 297 | 126 | |
Net income (loss) | 200 | 125 | 739 | 887 | |
Less: Net income (loss) attributable to noncontrolling interests | 71 | 92 | 323 | 400 | |
Net income (loss) attributable to The Williams Companies Inc | $ 129 | $ 33 | $ 416 | $ 487 | |
Net income (loss) | $ 0.13 | $ 0.04 | $ 0.47 | $ 0.59 | |
Net income (loss) | $ 0.13 | $ 0.04 | $ 0.46 | $ 0.59 | |
Net income (loss) | $ 206 | $ 122 | $ 748 | $ 893 | |
Less: Comprehensive income (loss) attributable to noncontrolling interests | 72 | 89 | 321 | 398 | |
Comprehensive income (loss) attributable to The Williams Companies, Inc. | 134 | 33 | 427 | 495 | |
Inventories | 153 | 153 | $ 113 | ||
Other current assets and deferred charges | 242 | 242 | 184 | ||
Total current assets | 1,984 | 1,984 | 2,179 | ||
Investments | 7,427 | 7,427 | 6,552 | ||
Property, plant, and equipment | 39,953 | 39,953 | 39,513 | ||
Property, plant, and equipment – net | 28,674 | 28,674 | 28,211 | ||
Intangible assets - net of accumulated amortization | 8,324 | 8,324 | 8,791 | ||
Regulatory assets, deferred charges, and other | 744 | 744 | 619 | ||
Total assets | 47,153 | 47,153 | 46,352 | ||
Deferred income tax liabilities | 1,648 | 1,648 | 3,147 | ||
Regulatory liabilities, deferred income, and other | 4,376 | 4,376 | 3,950 | ||
Retained deficit | (9,018) | (9,018) | (8,434) | ||
Total stockholders’ equity | 15,610 | 15,610 | 9,656 | ||
Noncontrolling interests in consolidated subsidiaries | 1,349 | 1,349 | 6,519 | ||
Total equity | 16,959 | 16,959 | 16,175 | ||
Total liabilities and equity | 47,153 | 47,153 | $ 46,352 | ||
Adoption of ASC 606 | (121) | ||||
Deconsolidation of subsidiary | (267) | ||||
Net increase (decrease) in equity | 784 | ||||
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | |||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||
Service revenues – commodity consideration | (121) | (316) | |||
Total revenues | (72) | (214) | |||
Processing commodity expenses | (30) | (91) | |||
Operating Costs and Expenses | 3 | ||||
Depreciation and amortization expenses | 1 | 2 | |||
Total costs and expenses | (77) | (229) | |||
Operating Income (Loss) | 5 | 15 | |||
Equity earnings (losses) | 1 | ||||
Other investing income (loss) - net | (9) | ||||
Interest incurred | 4 | 11 | |||
Interest capitalized | (2) | (6) | |||
Income (loss) before income taxes | 7 | 12 | |||
Provision (benefit) for income taxes | 1 | 1 | |||
Net income (loss) | 6 | 11 | |||
Less: Net income (loss) attributable to noncontrolling interests | (1) | ||||
Net income (loss) attributable to The Williams Companies Inc | $ 7 | $ 11 | |||
Net income (loss) | $ 0.01 | $ 0.01 | |||
Net income (loss) | $ 0.01 | $ 0.01 | |||
Net income (loss) | $ 6 | $ 11 | |||
Less: Comprehensive income (loss) attributable to noncontrolling interests | (1) | ||||
Comprehensive income (loss) attributable to The Williams Companies, Inc. | 7 | 11 | |||
Inventories | (8) | (8) | |||
Other current assets and deferred charges | (53) | (53) | |||
Total current assets | (61) | (61) | |||
Investments | (1) | (1) | |||
Property, plant, and equipment | (6) | (6) | |||
Property, plant, and equipment – net | (6) | (6) | |||
Intangible assets - net of accumulated amortization | 63 | 63 | |||
Regulatory assets, deferred charges, and other | (4) | (4) | |||
Total assets | (9) | (9) | |||
Deferred income tax liabilities | 27 | 27 | |||
Regulatory liabilities, deferred income, and other | (159) | (159) | |||
Retained deficit | 95 | 95 | |||
Total stockholders’ equity | 95 | 95 | |||
Noncontrolling interests in consolidated subsidiaries | 28 | 28 | |||
Total equity | 123 | 123 | |||
Total liabilities and equity | (9) | (9) | |||
Adoption of ASC 606 | 121 | ||||
Deconsolidation of subsidiary | (9) | ||||
Net increase (decrease) in equity | 123 | ||||
Calculated under Revenue Guidance in Effect before Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | |||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||
Service revenues – commodity consideration | 0 | 0 | |||
Total revenues | 2,231 | 6,268 | |||
Processing commodity expenses | 0 | 0 | |||
Operating Costs and Expenses | 1,137 | ||||
Depreciation and amortization expenses | 426 | 1,292 | |||
Total costs and expenses | 1,725 | 4,851 | |||
Operating Income (Loss) | 506 | 1,417 | |||
Equity earnings (losses) | 280 | ||||
Other investing income (loss) - net | 65 | ||||
Interest incurred | (282) | (845) | |||
Interest capitalized | 14 | 32 | |||
Income (loss) before income taxes | 397 | 1,048 | |||
Provision (benefit) for income taxes | 191 | 298 | |||
Net income (loss) | 206 | 750 | |||
Less: Net income (loss) attributable to noncontrolling interests | 70 | ||||
Net income (loss) attributable to The Williams Companies Inc | $ 136 | $ 427 | |||
Net income (loss) | $ 0.14 | $ 0.48 | |||
Net income (loss) | $ 0.14 | $ 0.47 | |||
Net income (loss) | $ 212 | $ 759 | |||
Less: Comprehensive income (loss) attributable to noncontrolling interests | 71 | ||||
Comprehensive income (loss) attributable to The Williams Companies, Inc. | 141 | 438 | |||
Inventories | 145 | 145 | |||
Other current assets and deferred charges | 189 | 189 | |||
Total current assets | 1,923 | 1,923 | |||
Investments | 7,426 | 7,426 | |||
Property, plant, and equipment | 39,947 | 39,947 | |||
Property, plant, and equipment – net | 28,668 | 28,668 | |||
Intangible assets - net of accumulated amortization | 8,387 | 8,387 | |||
Regulatory assets, deferred charges, and other | 740 | 740 | |||
Total assets | 47,144 | 47,144 | |||
Deferred income tax liabilities | 1,675 | 1,675 | |||
Regulatory liabilities, deferred income, and other | 4,217 | 4,217 | |||
Retained deficit | (8,923) | (8,923) | |||
Total stockholders’ equity | 15,705 | 15,705 | |||
Noncontrolling interests in consolidated subsidiaries | 1,377 | 1,377 | |||
Total equity | 17,082 | 17,082 | |||
Total liabilities and equity | 47,144 | 47,144 | |||
Adoption of ASC 606 | 0 | ||||
Deconsolidation of subsidiary | (276) | ||||
Net increase (decrease) in equity | 907 | ||||
Service [Member] | |||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,371 | 1,310 | 4,062 | 3,853 | |
Service [Member] | Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | |||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 5 | 16 | |||
Service [Member] | Calculated under Revenue Guidance in Effect before Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | |||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,376 | 4,078 | |||
Product [Member] | |||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 811 | 581 | 2,104 | 1,950 | |
Product [Member] | Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | |||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 44 | 86 | |||
Product [Member] | Calculated under Revenue Guidance in Effect before Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | |||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||
Revenue from Contract with Customer, Excluding Assessed Tax | 855 | 2,190 | |||
Oil and Gas, Purchased [Member] | |||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||
Product costs | 790 | $ 504 | 2,039 | $ 1,620 | |
Oil and Gas, Purchased [Member] | Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | |||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||
Product costs | (48) | (143) | |||
Oil and Gas, Purchased [Member] | Calculated under Revenue Guidance in Effect before Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | |||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||||
Product costs | $ 742 | $ 1,896 |
Variable Interest Entities (Det
Variable Interest Entities (Details) - USD ($) $ in Millions | 9 Months Ended | ||
Sep. 30, 2018 | Dec. 31, 2017 | [1] | |
Variable Interest Entity, Primary Beneficiary [Member] | Cash and Cash Equivalents [Member] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Assets | $ 32 | $ 881 | |
Variable Interest Entity, Primary Beneficiary [Member] | Trade accounts and other receivables - net [Member] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Assets | 57 | 972 | |
Variable Interest Entity, Primary Beneficiary [Member] | Inventories [Member] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Assets | 0 | 113 | |
Variable Interest Entity, Primary Beneficiary [Member] | Other Current Assets [Member] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Assets | 1 | 176 | |
Variable Interest Entity, Primary Beneficiary [Member] | Investments [Member] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Assets | 0 | 6,552 | |
Variable Interest Entity, Primary Beneficiary [Member] | Property Plant And Equipment, net [Member] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Assets | 2,398 | 27,912 | |
Variable Interest Entity, Primary Beneficiary [Member] | Intangible Assets, net [Member] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Assets | 1,189 | 8,790 | |
Variable Interest Entity, Primary Beneficiary [Member] | Regulatory assets, Deferred Charges, and Other Noncurrent Assets [Member] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Assets | 0 | 507 | |
Variable Interest Entity, Primary Beneficiary [Member] | Accounts Payable [Member] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities | (16) | (957) | |
Variable Interest Entity, Primary Beneficiary [Member] | Accrued Liabilities including current asset retirement obligations [Member] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities | (98) | (857) | |
Variable Interest Entity, Primary Beneficiary [Member] | Long-term debt due within one year [Member] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities | 0 | (501) | |
Variable Interest Entity, Primary Beneficiary [Member] | Long-term Debt [Member] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities | 0 | (15,996) | |
Variable Interest Entity, Primary Beneficiary [Member] | Deferred Income Tax Liabilities [Member] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities | 0 | (16) | |
Variable Interest Entity, Primary Beneficiary [Member] | Noncurrent Asset Retirement Obligation [Member] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities | (104) | (944) | |
Variable Interest Entity, Primary Beneficiary [Member] | Other Noncurrent Liabilities [Member] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities | $ (189) | $ (2,809) | |
Variable Interest Entity, Primary Beneficiary [Member] | Gulfstar One [Member] | |||
Variable Interest Entity [Line Items] | |||
Variable Interest Entity Ownership Percentage | 51.00% | ||
Variable Interest Entity, Primary Beneficiary [Member] | Constitution Pipeline Company LLC [Member] | |||
Variable Interest Entity [Line Items] | |||
Variable Interest Entity Ownership Percentage | 41.00% | ||
Variable Interest Entity, Primary Beneficiary [Member] | Constitution Pipeline Company LLC [Member] | Estimated Remaining Construction Costs For Variable Interest Entity [Member] | |||
Variable Interest Entity [Line Items] | |||
Other commitment | $ 740 | ||
Variable Interest Entity, Primary Beneficiary [Member] | Constitution Pipeline Company LLC [Member] | Property Plant And Equipment, net [Member] | |||
Variable Interest Entity [Line Items] | |||
Capitalized Project Development Costs | $ 377 | ||
Variable Interest Entity, Primary Beneficiary [Member] | Cardinal Gas Services LLC [Member] | |||
Variable Interest Entity [Line Items] | |||
Variable Interest Entity Ownership Percentage | 66.00% | ||
Variable Interest Entity, Not Primary Beneficiary [Member] | Jackalope Gas Gathering Services LLC [Member] | |||
Variable Interest Entity [Line Items] | |||
Variable Interest Entity Ownership Percentage | 50.00% | ||
Variable Interest Entity, Not Primary Beneficiary [Member] | Jackalope Gas Gathering Services LLC [Member] | Estimated Remaining Construction Costs For Variable Interest Entity [Member] | |||
Variable Interest Entity [Line Items] | |||
Other commitment | $ 400 | ||
Variable Interest Entity, Not Primary Beneficiary [Member] | Jackalope Gas Gathering Services LLC [Member] | Investments [Domain] | |||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | |||
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets and Liabilities, Net | $ 316 | ||
[1] | Includes WPZ, which was a consolidated VIE at December 31, 2017 (see Note 1 – General, Description of Business, and Basis of Presentation). |
Divestitures and Assets Held _3
Divestitures and Assets Held for Sale (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||||||
Dec. 31, 2018 | Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Oct. 01, 2018 | Dec. 31, 2017 | Oct. 26, 2017 | Jul. 06, 2017 | |
Income Statement and Additional Disclosures by Disposal Groups [Line Items] | |||||||||
Gain (Loss) on Disposition of Assets | $ 0 | $ 1,095 | $ 0 | $ 1,095 | |||||
Income (Loss) from Individually Significant Component Disposed of Attributable to Parent, before Income Tax [Abstract] | |||||||||
Disposal Group, Including Discontinued Operation, Assets, Current | 664 | 664 | $ 7 | ||||||
Disposal Group, Including Discontinued Operation, Liabilities, Current | 49 | 49 | $ 0 | ||||||
Williams Olefins, L.L.C. [Member] | |||||||||
Income Statement and Additional Disclosures by Disposal Groups [Line Items] | |||||||||
Disposal Group, Consideration | $ 12 | ||||||||
Four Corners [Member] | |||||||||
Income Statement and Additional Disclosures by Disposal Groups [Line Items] | |||||||||
Disposal Group, Consideration | 113 | 113 | |||||||
Four Corners [Member] | West [Member] | |||||||||
Income (Loss) from Individually Significant Component Disposed of Attributable to Parent, before Income Tax [Abstract] | |||||||||
Income (loss) before income taxes of disposal group | 25 | 14 | 52 | 31 | |||||
Income (loss) before income taxes of disposal group attributable to the Williams Companies, Inc. | 23 | 10 | 43 | 23 | |||||
Disposal Group, Including Discontinued Operation, Assets, Current | 23 | 23 | |||||||
Disposal Group, Including Discontinued Operation, Property, Plant and Equipment | 539 | 539 | |||||||
Disposal Group, Including Discontinued Operation, Assets, Noncurrent | 12 | 12 | |||||||
Disposal Group, Including Discontinued Operation, Assets | 574 | 574 | |||||||
Disposal Group, Including Discontinued Operation, Liabilities, Current | 22 | 22 | |||||||
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent | 23 | 23 | |||||||
Disposal Group, Including Discontinued Operation, Liabilities | 45 | 45 | |||||||
Four Corners [Member] | Subsequent Event [Member] | West [Member] | |||||||||
Income Statement and Additional Disclosures by Disposal Groups [Line Items] | |||||||||
Disposal Group, Consideration | $ 1,125 | ||||||||
Gain (Loss) on Disposition of Assets | $ 600 | ||||||||
Other [Member] | |||||||||
Income Statement and Additional Disclosures by Disposal Groups [Line Items] | |||||||||
Disposal Group, Including Discontinued Operation, Other Assets, Current | 2 | 2 | |||||||
Income (Loss) from Individually Significant Component Disposed of Attributable to Parent, before Income Tax [Abstract] | |||||||||
Disposal Group, Including Discontinued Operation, Property, Plant and Equipment | 84 | 84 | |||||||
Disposal Group, Including Discontinued Operation, Liabilities, Current | 1 | 1 | |||||||
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent | 3 | 3 | |||||||
Geismar [Member] | Williams Olefins, L.L.C. [Member] | |||||||||
Income Statement and Additional Disclosures by Disposal Groups [Line Items] | |||||||||
Disposal Group, Consideration | $ 2,084 | ||||||||
Gain (Loss) on Disposition of Business | 1,095 | ||||||||
Income (Loss) from Individually Significant Component Disposed of Attributable to Parent, before Income Tax [Abstract] | |||||||||
Income (loss) before income taxes of disposal group | 0 | 1 | 0 | 26 | |||||
Income (loss) before income taxes of disposal group attributable to the Williams Companies, Inc. | $ 0 | 1 | $ 0 | $ 19 | |||||
Long-term debt retired | $ 850 |
Investing Activities (Details)
Investing Activities (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||||||
Sep. 30, 2018 | Jun. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Jul. 30, 2018 | Dec. 31, 2017 | Mar. 31, 2017 | |
Schedule of Equity Method Investments [Line Items] | ||||||||
Equity Method Investments | $ 7,427 | $ 7,427 | $ 6,552 | |||||
Payments to Acquire Equity Method Investments | 803 | $ 103 | ||||||
Proceeds from Sale of Equity Method Investments | 0 | 200 | ||||||
Gain from sale of an equity-method investment interest | 0 | 269 | ||||||
Other investing income (loss) - net | 2 | $ 4 | 74 | 278 | ||||
West [Member] | Rocky Mountain Midstream Holdings LLC [Member] | ||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||
Equity Method Investments | $ 569 | $ 569 | ||||||
Equity Method Investment, Ownership Percentage | 43.00% | 43.00% | 40.00% | |||||
West [Member] | Jackalope Gas Gathering Services LLC [Member] | ||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||
Deconsolidation, Revaluation of Retained Investment, Gain (Loss), Amount | $ 62 | |||||||
Equity Method Investment, Ownership Percentage | 50.00% | 50.00% | ||||||
Equity Method Investment, Summarized Financial Information [Abstract] | ||||||||
Goodwill, Period Increase (Decrease) | $ 47 | |||||||
West [Member] | Delaware Basin Gas Gathering System [Member] | ||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||
Equity Method Investment, Ownership Percentage | 50.00% | |||||||
Proceeds from Sale of Equity Method Investments | 155 | |||||||
Gain from sale of an equity-method investment interest | 269 | |||||||
West [Member] | Ranch Westex JV LLC [Member] | ||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||
Proceeds from Sale of Equity Method Investments | $ 45 | |||||||
Northeast G And P [Member] | Appalachia Midstream Services, LLC [Member] | ||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||
Equity Method Investment, Ownership Percentage | 66.00% | 66.00% | ||||||
Northeast G And P [Member] | Laurel Mountain Midstream, LLC [Member] | ||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||
Equity Method Investment, Ownership Percentage | 69.00% | 69.00% | ||||||
Jackalope Gas Gathering Services LLC [Member] | West [Member] | ||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||
Investments, Fair Value Disclosure | $ 310 | |||||||
Appalachia Midstream Services, LLC [Member] | Northeast G And P [Member] | ||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||
Investments, Fair Value Disclosure | $ 1,100 | |||||||
Measurement Input, Discount Rate [Member] | Jackalope Gas Gathering Services LLC [Member] | West [Member] | ||||||||
Equity Method Investment, Summarized Financial Information [Abstract] | ||||||||
Property Plant And Equipment And Intangibles Fair Value Inputs | 10.90% | |||||||
Measurement Input, Discount Rate [Member] | Appalachia Midstream Services, LLC [Member] | Northeast G And P [Member] | ||||||||
Equity Method Investment, Summarized Financial Information [Abstract] | ||||||||
Property Plant And Equipment And Intangibles Fair Value Inputs | 9.50% | |||||||
Scenario, Plan [Member] | West [Member] | Rocky Mountain Midstream Holdings LLC [Member] | ||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||
Equity Method Investment, Ownership Percentage | 50.00% | 50.00% | ||||||
Payments to Acquire Equity Method Investments | $ 177 |
Other Income and Expenses (Deta
Other Income and Expenses (Details) - USD ($) $ in Millions | Mar. 28, 2018 | Jul. 03, 2017 | Feb. 23, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 |
Segment Reporting Information [Line Items] | |||||||
Gain on sale of Refinery Grade Propylene Splitter | $ 0 | $ 1,095 | $ 0 | $ 1,095 | |||
Debt Instrument, Unamortized Discount (Premium), Net | $ 7 | $ 3 | $ 30 | ||||
Unamortized Loan Commitment and Origination Fees and Unamortized Discounts or Premiums | 27 | 51 | 53 | ||||
Debt Instrument, Unamortized Premium | 34 | 54 | 23 | ||||
Other income (expense) - net [Member] | Atlantic Gulf [Member] | |||||||
Segment Reporting Information [Line Items] | |||||||
Amortization of regulatory assets associated with asset retirement obligations | 8 | 8 | 24 | 25 | |||
Accrual of regulatory liability related to overcollection of certain employee expenses | 5 | 5 | 16 | 16 | |||
Project development costs related to Constitution (see Note 3) | 1 | 4 | 4 | 12 | |||
Gain on asset retirement | (10) | (5) | (10) | (5) | |||
Regulatory Charge Resulting From Tax Rate Change | 0 | 0 | (10) | 0 | |||
Other income (expense) - net [Member] | West [Member] | |||||||
Segment Reporting Information [Line Items] | |||||||
Adjustments to regulatory liabilities related to Tax Reform | 6 | 0 | 18 | 0 | |||
Regulatory Charge Resulting From Tax Rate Change | 0 | 0 | (7) | 0 | |||
Gains on contract settlements and terminations | 0 | 0 | 0 | (15) | |||
Other income (expense) - net [Member] | Other [Member] | |||||||
Segment Reporting Information [Line Items] | |||||||
Benefit of regulatory asset associated with increase in Transco's estimated deferred state income tax rate following WPZ Merger | (37) | 0 | (37) | 0 | |||
Gain on sale of Refinery Grade Propylene Splitter | 0 | 0 | 0 | (12) | |||
Selling, general, and administrative expenses [Member] | Other [Member] | |||||||
Segment Reporting Information [Line Items] | |||||||
Noncash Contribution Expense | 35 | ||||||
WPZ Merger | 15 | 19 | |||||
Severance and other related costs | 5 | 18 | |||||
Other Nonoperating Income (Expense) [Member] | Atlantic Gulf [Member] | |||||||
Segment Reporting Information [Line Items] | |||||||
Allowance for funds used during construction, capitalized cost of equity | 33 | 17 | 80 | 55 | |||
Deferred taxes on equity funds used during construction [Member] | Other [Member] | |||||||
Segment Reporting Information [Line Items] | |||||||
Allowance for funds used during construction, capitalized cost of equity | 22 | 8 | 31 | 44 | |||
Northwest Pipeline LLC [Member] | Other income (expense) - net [Member] | West [Member] | |||||||
Segment Reporting Information [Line Items] | |||||||
Regulatory Charge Resulting From Tax Rate Change | $ (12) | $ 0 | $ (12) | $ 0 | |||
4.875% Senior Unsecured Notes due 2024 [Member] | |||||||
Segment Reporting Information [Line Items] | |||||||
Long-term debt retired | $ 750 | ||||||
Long-term debt interest rate | 4.875% | ||||||
4.875% Senior Unsecured Notes due 2023 [Member] | |||||||
Segment Reporting Information [Line Items] | |||||||
Long-term debt retired | $ 1,400 | ||||||
Long-term debt interest rate | 4.875% | ||||||
6.125% Senior Unsecured Notes due 2022 [Member] | |||||||
Segment Reporting Information [Line Items] | |||||||
Long-term debt retired | $ 750 | ||||||
Long-term debt interest rate | 6.125% |
Provision (Benefit) for Incom_3
Provision (Benefit) for Income Taxes (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Aug. 10, 2018 | Dec. 31, 2017 | |
Current: | ||||||
Federal | $ (19) | $ 7 | $ (55) | $ 10 | ||
State | 0 | 9 | 1 | 17 | ||
Total | (19) | 16 | (54) | 27 | ||
Deferred: | ||||||
Federal | 188 | (11) | 312 | 63 | ||
State | 21 | 19 | 39 | 36 | ||
Total | 209 | 8 | 351 | 99 | ||
Provision (benefit) for income taxes | 190 | 24 | 297 | 126 | ||
Provision Related To Increase In Deferred State Income Tax Rate | $ 18 | 38 | 18 | |||
Valuation Allowance, Deferred Tax Asset, Decrease Amount | 31 | $ 127 | ||||
Income Tax Contingency [Line Items] | ||||||
Tax Credit Carryforward, Valuation Allowance | 105 | 105 | ||||
Deferred Tax Liabilities, Net, Noncurrent | $ (1,648) | $ (1,648) | $ (3,147) | |||
WPZ Merger Public Unit Exchange [Member] | ||||||
Income Tax Contingency [Line Items] | ||||||
Deferred Tax Liabilities, Net, Noncurrent | $ 1,829 |
Earnings Per Common Share (Deta
Earnings Per Common Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Earnings Per Share Table [Line Items] | ||||
Net income available to common stockholders | $ 129 | $ 33 | $ 416 | $ 487 |
Basic weighted-average shares | 1,023,587 | 826,779 | 893,706 | 825,925 |
Effect of dilutive securities: | ||||
Diluted weighted-average shares | 1,026,504 | 829,368 | 896,322 | 828,150 |
Earnings per common share: | ||||
Basic | $ 0.13 | $ 0.04 | $ 0.47 | $ 0.59 |
Diluted | $ 0.13 | $ 0.04 | $ 0.46 | $ 0.59 |
Nonvested restricted stock units [Member] | ||||
Effect of dilutive securities: | ||||
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements | 2,387 | 1,889 | 2,102 | 1,567 |
Stock Options [Member] | ||||
Effect of dilutive securities: | ||||
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements | 530 | 700 | 514 | 658 |
Employee Benefit Plans (Quarter
Employee Benefit Plans (Quarterly Info) (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Pension Benefits [Member] | ||||
Components of net periodic benefit cost (credit): | ||||
Service cost | $ 12 | $ 13 | $ 37 | $ 38 |
Interest cost | 12 | 15 | 35 | 44 |
Expected return on plan assets | (16) | (21) | (47) | (62) |
Amortization of net actuarial loss | 6 | 6 | 17 | 20 |
Net actuarial loss from settlements | 1 | 0 | 2 | 0 |
Net periodic benefit cost (credit) | 15 | 13 | 44 | 40 |
Employer contributions | 87 | |||
Estimated future employer contributions in current fiscal year | 1 | 1 | ||
Other Postretirement Benefits [Member] | ||||
Components of net periodic benefit cost (credit): | ||||
Service cost | 1 | 0 | 1 | 1 |
Interest cost | 1 | 2 | 5 | 6 |
Expected return on plan assets | (2) | (3) | (8) | (9) |
Amortization of prior service cost (credit) | 0 | (3) | (1) | (10) |
Reclassification to regulatory liability | 0 | 1 | 1 | 3 |
Net periodic benefit cost (credit) | 0 | (3) | (2) | (9) |
Amortization of prior service cost (credit) from regulatory assets (liabilities) | $ (2) | (1) | $ (6) | |
Employer contributions | 4 | |||
Estimated future employer contributions in current fiscal year | $ 2 | $ 2 |
Debt and Banking Arrangements L
Debt and Banking Arrangements Long-Term Debt Issuances and Retirements (Details 1) - USD ($) $ in Millions | Jun. 15, 2018 | Mar. 28, 2018 | Oct. 31, 2018 | Sep. 30, 2018 | Aug. 24, 2018 | Mar. 15, 2018 | Mar. 05, 2018 |
Transcontinental Gas Pipe Line Company, LLC [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Proceeds from Issuance of Other Long-term Debt | $ 29 | ||||||
Transcontinental Gas Pipe Line Company, LLC [Member] | Subsequent Event [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Term | 20 years | ||||||
Percent Of Construction Costs Capitalized | 100.00% | ||||||
Other Long-term Debt | $ 790 | ||||||
4.875% Senior Unsecured Notes due 2024 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term debt interest rate | 4.875% | ||||||
Long-term debt retired | $ 750 | ||||||
4.85%SeniorUnsecuredNotesDue2048 [Member] | Williams Partners L.P. [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term debt face amount | $ 800 | ||||||
Long-term debt interest rate | 4.85% | ||||||
4%SeniorUnsecuredNotesDue2028 [Member] | Transcontinental Gas Pipe Line Company, LLC [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term debt face amount | $ 400 | ||||||
Long-term debt interest rate | 4.00% | ||||||
4.6%SeniorUnsecuredNotesDue2048 [Member] | Transcontinental Gas Pipe Line Company, LLC [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term debt face amount | $ 600 | ||||||
Long-term debt interest rate | 4.60% | ||||||
6.05% Senior Unsecured Notes due 2018 [Member] | Transcontinental Gas Pipe Line Company, LLC [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term debt interest rate | 6.05% | ||||||
Long-term debt retired | $ 250 | ||||||
6.05% Senior Unsecured Notes due 2018 [Member] | Northwest Pipeline LLC [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term debt interest rate | 6.05% | ||||||
Long-term debt retired | $ 250 | ||||||
4% Senior Unsecured Notes Due 2027 [Member] | Northwest Pipeline LLC [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term debt face amount | $ 250 | ||||||
Long-term debt interest rate | 4.00% | ||||||
Additional interest rate accrued for default of registration rights agreements first period | 0.25% | ||||||
Additional interest rate accrued for default of registration rights agreements each subsequent period | 0.25% | ||||||
Maximum additional interest rate accrued for default of registration rights agreements all periods | 0.50% |
Debt and Banking Arrangements C
Debt and Banking Arrangements Credit Facilities and Commercial Paper (Details 2) $ in Millions | Aug. 10, 2018USD ($) | Oct. 31, 2018 | Oct. 30, 2018USD ($) | Sep. 30, 2018USD ($) | Dec. 31, 2017USD ($) | ||
Credit Facility and Commercial Paper [Line Items] | |||||||
Commercial paper, outstanding | $ 823 | $ 0 | |||||
Williams Companies Inc [Member] | |||||||
Credit Facility and Commercial Paper [Line Items] | |||||||
Credit facility, capacity | $ 4,500 | 4,500 | [1] | ||||
Credit facility, loans outstanding | [1] | 0 | |||||
Additional Amount By Which Credit Facility Can Be Increased | 500 | ||||||
Acquisition Trigger Amount | $ 25 | ||||||
Maximum Ratio Of Debt To EBITDA After Acquisition | 5.5 | ||||||
Williams Companies Inc [Member] | Sep18Dec18Mar19Jun19 [Member] | |||||||
Credit Facility and Commercial Paper [Line Items] | |||||||
Maximum Ratio Of Debt To EBITDA | 5.75 | ||||||
Williams Companies Inc [Member] | Sep19Dec19 [Member] | |||||||
Credit Facility and Commercial Paper [Line Items] | |||||||
Maximum Ratio Of Debt To EBITDA | 5.5 | ||||||
Williams Companies Inc [Member] | Mar20 And Subsequent Quarters [Member] | |||||||
Credit Facility and Commercial Paper [Line Items] | |||||||
Maximum Ratio Of Debt To EBITDA | 5 | ||||||
Northwest Pipeline LLC [Member] | |||||||
Credit Facility and Commercial Paper [Line Items] | |||||||
Credit facility, capacity | $ 500 | ||||||
Maximum Ratio Of Debt To EBITDA | 0.65 | ||||||
Transcontinental Gas Pipe Line Company, LLC [Member] | |||||||
Credit Facility and Commercial Paper [Line Items] | |||||||
Credit facility, capacity | $ 500 | ||||||
Maximum Ratio Of Debt To EBITDA | 0.65 | ||||||
Commercial Paper [Member] | Williams Companies Inc [Member] | |||||||
Credit Facility and Commercial Paper [Line Items] | |||||||
Credit facility, capacity | $ 4,000 | ||||||
Commercial paper, outstanding | $ 824 | ||||||
Debt Instrument, Term | 397 days | ||||||
Short-term Debt, Weighted Average Interest Rate, at Point in Time | 2.73% | ||||||
Commercial Paper [Member] | Williams Partners L.P. [Member] | |||||||
Credit Facility and Commercial Paper [Line Items] | |||||||
Credit facility, capacity | $ 3,000 | ||||||
Letters Of Credit Under Certain Bilateral Bank Agreements [Member] | Williams Companies Inc [Member] | |||||||
Credit Facility and Commercial Paper [Line Items] | |||||||
Credit facility, letters of credit outstanding | $ 14 | ||||||
SwingLine Loan [Member] | Williams Companies Inc [Member] | |||||||
Credit Facility and Commercial Paper [Line Items] | |||||||
Credit facility, capacity | 200 | ||||||
Letter of Credit [Member] | Williams Companies Inc [Member] | |||||||
Credit Facility and Commercial Paper [Line Items] | |||||||
Credit facility, capacity | $ 1,000 | ||||||
Subsequent Event [Member] | Transcontinental Gas Pipe Line Company, LLC [Member] | |||||||
Credit Facility and Commercial Paper [Line Items] | |||||||
Debt Instrument, Term | 20 years | ||||||
Subsequent Event [Member] | Commercial Paper [Member] | |||||||
Credit Facility and Commercial Paper [Line Items] | |||||||
Commercial paper, outstanding | $ 0 | ||||||
[1] | In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. |
Stockholders' Equity Issuance O
Stockholders' Equity Issuance Of Preferred Shares (Details) - USD ($) $ / shares in Units, $ in Millions | 1 Months Ended | ||
Jul. 31, 2018 | Sep. 30, 2018 | Dec. 31, 2017 | |
Class of Stock [Line Items] | |||
Preferred Stock, Value | $ 35 | $ 0 | |
Series B Preferred Stock [Member] | |||
Class of Stock [Line Items] | |||
Stock Issued During Period, Shares, New Issues | 35,000 | ||
Preferred Stock, Value | $ 35 | ||
Preferred Stock, Dividend Rate, Percentage | 7.25% | ||
Dividends, Preferred Stock, Cash | $ 0.4 | ||
Preferred Stock, Shares Authorized | 30,000,000 | ||
Preferred Stock, Par or Stated Value Per Share | $ 1 |
Stockholders' Equity Table Of C
Stockholders' Equity Table Of Changes In AOCI (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Jan. 01, 2018 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||
Total, Beginning Balance | $ (238) | ||||
WPZ Merger (Note 1) | 1,862 | ||||
Other comprehensive income (loss) | $ 6 | $ (3) | 9 | $ 6 | |
Total, Ending Balance | (291) | (291) | |||
Accumulated Other Comprehensive Income (Loss) [Member] | |||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||
Total, Beginning Balance | (238) | ||||
Adoption of ASU 2018-02 (Note 1) | $ (61) | ||||
WPZ Merger (Note 1) | (3) | ||||
Other comprehensive income (loss) before reclassifications | (10) | ||||
Amounts reclassified from accumulated other comprehensive income (loss) | 21 | ||||
Other comprehensive income (loss) | 11 | ||||
Total, Ending Balance | (291) | (291) | |||
Cash Flow Hedges | |||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||
Total, Beginning Balance | (2) | ||||
Adoption of ASU 2018-02 (Note 1) | 0 | ||||
WPZ Merger (Note 1) | (3) | ||||
Other comprehensive income (loss) before reclassifications | (14) | ||||
Amounts reclassified from accumulated other comprehensive income (loss) | 7 | ||||
Other comprehensive income (loss) | (7) | ||||
Total, Ending Balance | (12) | (12) | |||
Foreign Currency Translation | |||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||
Total, Beginning Balance | (1) | ||||
Adoption of ASU 2018-02 (Note 1) | 0 | ||||
WPZ Merger (Note 1) | 0 | ||||
Other comprehensive income (loss) before reclassifications | 0 | ||||
Amounts reclassified from accumulated other comprehensive income (loss) | 0 | ||||
Other comprehensive income (loss) | 0 | ||||
Total, Ending Balance | (1) | (1) | |||
Pension and Other Postretirement Benefits | |||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||
Total, Beginning Balance | (235) | ||||
Adoption of ASU 2018-02 (Note 1) | $ (61) | ||||
WPZ Merger (Note 1) | 0 | ||||
Other comprehensive income (loss) before reclassifications | 4 | ||||
Amounts reclassified from accumulated other comprehensive income (loss) | 14 | ||||
Other comprehensive income (loss) | 18 | ||||
Total, Ending Balance | $ (278) | (278) | |||
Reclassification out of Accumulated Other Comprehensive Income [Member] | |||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||
Amounts reclassified from accumulated other comprehensive income (loss) | (24) | ||||
Amounts reclassified from accumulated other comprehensive income (loss) | $ 21 |
Stockholders' Equity Table Of R
Stockholders' Equity Table Of Reclassifications from AOCI (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||||
Total before tax | $ 32 | |||
Noncontrolling interest | $ 71 | $ 92 | 323 | $ 400 |
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | ||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||||
Net of income tax | (7) | |||
Pension and Other Postretirement Benefits | ||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||||
Net of income tax | (14) | |||
Foreign Currency Translation | ||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||||
Net of income tax | 0 | |||
Reclassification out of Accumulated Other Comprehensive Income [Member] | ||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||||
Income tax benefit | (8) | |||
Net of income tax | 24 | |||
Reclassifications during the period | (21) | |||
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Energy Commodity Contracts [Member] | ||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||||
Energy commodity contracts | 13 | |||
Reclassification out of Accumulated Other Comprehensive Income [Member] | Pension and Other Postretirement Benefits | ||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||||
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit) | 19 | |||
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Noncontrolling Interest [Member] | ||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||||
Noncontrolling interest | $ (3) |
Fair Value Measurements Recurri
Fair Value Measurements Recurring Measurements and Additional (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 | Sep. 30, 2017 |
Additional disclosures: | |||
Fair Value, Level 1 to level 2 Transfers, Amount | $ 0 | $ 0 | |
Fair Value, Level 2 to level 1 Transfers, Amount | 0 | $ 0 | |
Carrying Amount [Member] | |||
Additional disclosures: | |||
Other receivables | 21 | $ 7 | |
Long-term debt, including current portion | (21,442) | (20,935) | |
Guarantees | (43) | (43) | |
Fair Value [Member] | |||
Additional disclosures: | |||
Other receivables | 21 | 7 | |
Long-term debt, including current portion | (22,532) | (23,005) | |
Guarantees | (30) | (30) | |
Level 1 [Member] | |||
Additional disclosures: | |||
Other receivables | 21 | 7 | |
Long-term debt, including current portion | 0 | 0 | |
Guarantees | 0 | 0 | |
Level 2 [Member] | |||
Additional disclosures: | |||
Other receivables | 0 | 0 | |
Long-term debt, including current portion | (22,532) | (23,005) | |
Guarantees | (14) | (14) | |
Level 3 [Member] | |||
Additional disclosures: | |||
Other receivables | 0 | 0 | |
Long-term debt, including current portion | 0 | 0 | |
Guarantees | (16) | (16) | |
Fair Value, Measurements, Recurring [Member] | Carrying Amount [Member] | |||
Measured on a recurring basis: | |||
ARO Trust investments | 157 | 135 | |
Fair Value, Measurements, Recurring [Member] | Carrying Amount [Member] | Designated as Hedging Instrument [Member] | |||
Measured on a recurring basis: | |||
Energy derivatives liabilities | (14) | (3) | |
Fair Value, Measurements, Recurring [Member] | Carrying Amount [Member] | Not Designated as Hedging Instrument [Member] | |||
Measured on a recurring basis: | |||
Energy derivatives assets | 6 | ||
Energy derivatives liabilities | (9) | (3) | |
Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | |||
Measured on a recurring basis: | |||
ARO Trust investments | 157 | 135 | |
Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Designated as Hedging Instrument [Member] | |||
Measured on a recurring basis: | |||
Energy derivatives liabilities | (14) | (3) | |
Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Not Designated as Hedging Instrument [Member] | |||
Measured on a recurring basis: | |||
Energy derivatives assets | 6 | ||
Energy derivatives liabilities | (9) | (3) | |
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | |||
Measured on a recurring basis: | |||
ARO Trust investments | 157 | 135 | |
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Designated as Hedging Instrument [Member] | |||
Measured on a recurring basis: | |||
Energy derivatives liabilities | (13) | (2) | |
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Not Designated as Hedging Instrument [Member] | |||
Measured on a recurring basis: | |||
Energy derivatives assets | 6 | ||
Energy derivatives liabilities | (6) | 0 | |
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | |||
Measured on a recurring basis: | |||
ARO Trust investments | 0 | 0 | |
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Designated as Hedging Instrument [Member] | |||
Measured on a recurring basis: | |||
Energy derivatives liabilities | (1) | (1) | |
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Not Designated as Hedging Instrument [Member] | |||
Measured on a recurring basis: | |||
Energy derivatives assets | 0 | ||
Energy derivatives liabilities | 0 | 0 | |
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | |||
Measured on a recurring basis: | |||
ARO Trust investments | 0 | 0 | |
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Designated as Hedging Instrument [Member] | |||
Measured on a recurring basis: | |||
Energy derivatives liabilities | 0 | 0 | |
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Not Designated as Hedging Instrument [Member] | |||
Measured on a recurring basis: | |||
Energy derivatives assets | 0 | ||
Energy derivatives liabilities | (3) | $ (3) | |
WilTel Guarantee [Member] | |||
Additional disclosures: | |||
Guarantor Obligations, Maximum Exposure, Undiscounted | 29 | ||
Indemnification Agreement [Member] | Carrying Amount [Member] | |||
Additional disclosures: | |||
Guarantees | $ 0 |
Fair Value Measurements Nonrecu
Fair Value Measurements Nonrecurring Measurements (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||||||
Jun. 30, 2018 | Sep. 30, 2017 | Jun. 30, 2017 | [5] | Sep. 30, 2018 | Sep. 30, 2017 | ||||
Impairment Of Certain Assets [Member] | |||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract] | |||||||||
Impairment of certain assets | $ 66 | ||||||||
Other Asset Impairment Charges | $ 1,236 | ||||||||
Fair Value, Measurements, Nonrecurring [Member] | Impairment Of Certain Assets [Member] | |||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract] | |||||||||
Impairment of certain assets | [1] | 0 | 11 | ||||||
Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Property Plant And Equipment, Net And Intangible Assets, Net Of Accumulated Amortization [Member] | West [Member] | |||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract] | |||||||||
Property Plant And Equipment And Intangibles, Fair Value Disclosure | [2] | $ 439 | 439 | ||||||
Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Property Plant And Equipment, Net And Intangible Assets, Net Of Accumulated Amortization [Member] | Northeast G And P [Member] | |||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract] | |||||||||
Property Plant And Equipment And Intangibles, Fair Value Disclosure | [3] | 21 | 21 | ||||||
Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Property Plant And Equipment, net [Member] | Other [Member] | |||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract] | |||||||||
Fair Value of Property, Plant, and Equipment | 32 | [4] | $ 18 | 32 | [4] | ||||
Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Impairment Of Certain Assets [Member] | |||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract] | |||||||||
Other Asset Impairment Charges | $ 1,225 | ||||||||
Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Impairment Of Certain Assets [Member] | Other [Member] | |||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract] | |||||||||
Impairment of certain assets | 68 | [4] | $ 23 | ||||||
Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Impairment Of Certain Assets [Member] | West [Member] | |||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract] | |||||||||
Other Asset Impairment Charges | [2] | 1,019 | |||||||
Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Impairment Of Certain Assets [Member] | Northeast G And P [Member] | |||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract] | |||||||||
Other Asset Impairment Charges | [3] | $ 115 | |||||||
Fair Value, Measurements, Nonrecurring [Member] | Level 2 [Member] | Property Plant And Equipment, net [Member] | Other [Member] | |||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract] | |||||||||
Fair Value of Property, Plant, and Equipment | [6] | $ 25 | |||||||
Fair Value, Measurements, Nonrecurring [Member] | Level 2 [Member] | Impairment Of Certain Assets [Member] | |||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract] | |||||||||
Impairment of certain assets | $ 66 | ||||||||
Fair Value, Measurements, Nonrecurring [Member] | Level 2 [Member] | Impairment Of Certain Assets [Member] | Other [Member] | |||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract] | |||||||||
Impairment of certain assets | [6] | $ 66 | |||||||
Measurement Input, Discount Rate [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | West [Member] | |||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract] | |||||||||
Property Plant And Equipment And Intangibles Fair Value Inputs | 10.20% | 10.20% | |||||||
Measurement Input, Discount Rate [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Northeast G And P [Member] | |||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract] | |||||||||
Property Plant And Equipment And Intangibles Fair Value Inputs | 11.10% | 11.10% | |||||||
[1] | Reflects multiple individually insignificant impairments and write-downs of other certain assets that may no longer be in use or are surplus in nature for which the fair value was determined to be lower than the carrying value. | ||||||||
[2] | Relates to certain gathering operations in the Mid-Continent region. During the third quarter of 2017, we received solicitations and engaged in negotiations for the sale of certain of these assets which led to our impairment evaluation. The estimated fair value was determined using an income approach and incorporated market inputs based on ongoing negotiations for a potential sale of a portion of the underlying assets. For the income approach, we utilized a discount rate of 10.2 percent, reflecting an estimated cost of capital and risks associated with the underlying assets. | ||||||||
[3] | Relates to certain gathering operations in the Marcellus South region resulting from an anticipated decline in future volumes following a third-quarter 2017 shut-in by the primary producer. The estimated fair value was determined by the income approach utilizing a discount rate of 11.1 percent, reflecting an estimated cost of capital and risks associated with the underlying assets | ||||||||
[4] | Relates to an NGL pipeline near the Houston Ship Channel region which we anticipate will be underutilized for the foreseeable future. The estimated fair value was primarily determined by using a market approach based on our analysis of observable inputs in the principal market. | ||||||||
[5] | Relates primarily to project development costs associated with an olefins pipeline project in the Gulf Coast region, the likelihood of completion of which is now considered remote. The estimated fair value of the remaining pipe and equipment considered a market approach based on our analysis of observable inputs in the principal market, as well as an estimate of replacement cost. | ||||||||
[6] | Relates to certain idle pipelines. The estimated fair value was determined by a market approach incorporating information derived from bids received for these assets, which are currently being marketed for sale together with certain other assets. These inputs result in a fair value measurement within Level 2 of the fair value hierarchy. |
Contingent Liabilities (Details
Contingent Liabilities (Details) - USD ($) $ in Millions | May 20, 2016 | Sep. 30, 2018 |
Loss Contingencies [Line Items] | ||
Accrued environmental loss liabilities | $ 36 | |
Energy Transfer Merger [Member] | ||
Loss Contingencies [Line Items] | ||
Loss contingency, damages sought, value | $ 1,480 | |
Gas Pipeline [Member] | ||
Loss Contingencies [Line Items] | ||
Accrued environmental loss liabilities | 7 | |
Natural Gas Underground Storage Facilities [Member] | ||
Loss Contingencies [Line Items] | ||
Accrued environmental loss liabilities | 7 | |
Former Operations [Member] | ||
Loss Contingencies [Line Items] | ||
Accrued environmental loss liabilities | 22 | |
Maximum [Member] | Former Alaska Refinery [Member] | ||
Loss Contingencies [Line Items] | ||
Loss contingency, range of possible loss | $ 32 |
Segment Disclosures Reconciliat
Segment Disclosures Reconciliation of Segment Revenues to Consolidated (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 2,280 | $ 6,423 | ||
Service revenues – commodity consideration | 121 | $ 0 | 316 | $ 0 |
Total revenues | 2,303 | 1,891 | 6,482 | 5,803 |
Intersegment Elimination [Member] | ||||
Segment revenues | ||||
Service revenues – commodity consideration | 0 | 0 | ||
Total revenues | (147) | (101) | (365) | (400) |
Operating Segments [Member] | Northeast G And P [Member] | ||||
Segment revenues | ||||
Service revenues – commodity consideration | 6 | 14 | ||
Total revenues | 322 | 275 | 963 | 829 |
Operating Segments [Member] | Atlantic Gulf [Member] | ||||
Segment revenues | ||||
Service revenues – commodity consideration | 18 | 45 | ||
Total revenues | 756 | 670 | 2,180 | 2,012 |
Operating Segments [Member] | West [Member] | ||||
Segment revenues | ||||
Service revenues – commodity consideration | 97 | 257 | ||
Total revenues | 1,362 | 1,029 | 3,678 | 2,965 |
Operating Segments [Member] | Other [Member] | ||||
Segment revenues | ||||
Service revenues – commodity consideration | 0 | 0 | ||
Total revenues | 10 | 18 | 26 | 397 |
Service [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,371 | 1,310 | 4,062 | 3,853 |
Service [Member] | Northeast G And P [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 236 | 207 | 677 | 621 |
Service [Member] | Atlantic Gulf [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 595 | 553 | 1,769 | 1,620 |
Service [Member] | West [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 533 | 544 | 1,599 | 1,589 |
Service [Member] | Other [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 7 | 6 | 17 | 23 |
Service [Member] | Intersegment Elimination [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | (26) | (21) | (76) | (63) |
Service [Member] | Intersegment Elimination [Member] | Northeast G And P [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 11 | 7 | 30 | 27 |
Service [Member] | Intersegment Elimination [Member] | Atlantic Gulf [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 12 | 11 | 37 | 27 |
Service [Member] | Intersegment Elimination [Member] | West [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | 0 | 0 |
Service [Member] | Intersegment Elimination [Member] | Other [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 3 | 3 | 9 | 9 |
Service [Member] | Operating Segments [Member] | Northeast G And P [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 247 | 214 | 707 | 648 |
Service [Member] | Operating Segments [Member] | Atlantic Gulf [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 607 | 564 | 1,806 | 1,647 |
Service [Member] | Operating Segments [Member] | West [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 533 | 544 | 1,599 | 1,589 |
Service [Member] | Operating Segments [Member] | Other [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 10 | 9 | 26 | 32 |
Product [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 811 | 581 | 2,104 | 1,950 |
Product [Member] | Northeast G And P [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 59 | 56 | 214 | 159 |
Product [Member] | Atlantic Gulf [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 46 | 57 | 131 | 201 |
Product [Member] | West [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 706 | 459 | 1,759 | 1,233 |
Product [Member] | Other [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 9 | 0 | 357 |
Product [Member] | Intersegment Elimination [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | (121) | (80) | (289) | (337) |
Product [Member] | Intersegment Elimination [Member] | Northeast G And P [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 10 | 5 | 28 | 22 |
Product [Member] | Intersegment Elimination [Member] | Atlantic Gulf [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 85 | 49 | 198 | 164 |
Product [Member] | Intersegment Elimination [Member] | West [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 26 | 26 | 63 | 143 |
Product [Member] | Intersegment Elimination [Member] | Other [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | 0 | 8 |
Product [Member] | Operating Segments [Member] | Northeast G And P [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 69 | 61 | 242 | 181 |
Product [Member] | Operating Segments [Member] | Atlantic Gulf [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 131 | 106 | 329 | 365 |
Product [Member] | Operating Segments [Member] | West [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 732 | 485 | 1,822 | 1,376 |
Product [Member] | Operating Segments [Member] | Other [Member] | ||||
Segment revenues | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 0 | $ 9 | $ 0 | $ 365 |
Segment Disclosures Reconcili_2
Segment Disclosures Reconciliation of Segment Assets to Consolidated (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 | |
Segment assets: | |||
Total assets | $ 47,153 | $ 46,352 | |
Northeast G And P [Member] | |||
Segment assets: | |||
Total assets | 14,482 | 14,397 | |
Atlantic Gulf [Member] | |||
Segment assets: | |||
Total assets | 16,361 | 14,989 | |
West [Member] | |||
Segment assets: | |||
Total assets | 16,169 | 16,143 | |
Other [Member] | |||
Segment assets: | |||
Total assets | [1] | 748 | 1,449 |
Intersegment Elimination [Member] | |||
Segment assets: | |||
Total assets | [2] | $ (607) | $ (626) |
[1] | Decrease in Other Total assets due primarily to decreased cash balance. | ||
[2] | Total assets Eliminations primarily relate to the intercompany notes and accounts receivable generated by our cash management program. |
Segment Disclosures Reconcili_3
Segment Disclosures Reconciliation of Segment Modified EBITDA to Consolidated Net Income (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Reconciliation of Modified EBITDA to Net Income (Loss): | ||||
Modified EBITDA Earnings (Loss) | $ 1,191 | $ 939 | $ 3,369 | $ 3,148 |
Accretion expense associated with asset retirement obligations for nonregulated operations | (8) | (7) | (26) | (23) |
Depreciation and amortization expenses | (425) | (433) | (1,290) | (1,308) |
Equity earnings (losses) | 105 | 115 | 279 | 347 |
Other investing income (loss) - net | 2 | 4 | 74 | 278 |
Proportional Modified EBITDA of equity-method investments | (205) | (202) | (552) | (611) |
Interest expense | (270) | (267) | (818) | (818) |
(Provision) benefit for income taxes | (190) | (24) | (297) | (126) |
Net income (loss) | 200 | 125 | 739 | 887 |
Operating Segments [Member] | Northeast G And P [Member] | ||||
Reconciliation of Modified EBITDA to Net Income (Loss): | ||||
Modified EBITDA Earnings (Loss) | 281 | 115 | 786 | 588 |
Operating Segments [Member] | Atlantic Gulf [Member] | ||||
Reconciliation of Modified EBITDA to Net Income (Loss): | ||||
Modified EBITDA Earnings (Loss) | 492 | 430 | 1,418 | 1,334 |
Operating Segments [Member] | West [Member] | ||||
Reconciliation of Modified EBITDA to Net Income (Loss): | ||||
Modified EBITDA Earnings (Loss) | 412 | (615) | 1,214 | 126 |
Operating Segments [Member] | Other [Member] | ||||
Reconciliation of Modified EBITDA to Net Income (Loss): | ||||
Modified EBITDA Earnings (Loss) | $ 6 | $ 1,009 | $ (49) | $ 1,100 |